2020 Annual Report
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission file number: 001-38870
Brigham Minerals, Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction
of incorporation or organization)
5914 W. Courtyard Drive,
Suite 200
Austin,
Texas
(Address of principal executive offices)
83-1106283
(I.R.S. Employer
Identification No.)
78730
(Zip code)
(512) 220-6350
(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act:
Title of each class
Trading symbol(s)
Name of each exchange on which registered
Class A common stock, par value $0.01
MNRL
New York Stock Exchange
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in RuleRR
405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to
Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was
required to submit such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting
company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company”
and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
ff
☐
☐
Accelerated filer ☒
Smaller reporting company ☐
Emerging growth company ☒
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its
internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public
accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x
As of June 30, 2020, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of
voting and non-voting common stock held by non-affiliates of the registrant was approximately $515.5 million, determined using the per
share closing price on the New York Stock Exchange on that date of $12.35. Shares of common stock held by each director and executive
officer (and their respective affiliates) and each person who owns 10% or more of the outstanding common stock or who is otherwise believed
by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive
determination for other purposes.
The registrant had 43,558,494 shares of Class A common stock and 13,167,687 shares of Class B common stock outstanding as of
February 19, 2021.
Portions of the registrant’s definitive proxy statement for the 2021 Annual Meeting of Stockholders, to be filed no later than 120 days after
the end of the fiscal year to which this Annual Report on Form 10-K relates, are incorporated by reference into Part III of this Annual Report
on Form 10-K.
BRIGHAM MINERALS, INC.
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2020
TABLE OF CONTENTS
Glossary of Oil and Natural Gas Terms
Cautionary Statement Regarding Forward-Looking Statements
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
PART I
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
PART III
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
Item 15. Exhibits, Financial Statement Schedules
Item 16. Form 10-K Summary
Signatures
PART IV
4
6
8
31
57
57
57
57
58
59
62
85
86
86
86
87
88
88
88
88
88
89
90
91
3
GLOSSARY OF OIL AND NATURALRR
GAS TERMS
The folff
lowing are abbreviations and definitions of certain terms used in this Annual Report on Form 10-K ("Annual
Report"), which are commonly used in the oil and natural
t
gas industry:
Term
Basin
Bbl
Boe
Boe/d
British thermal unit or Btu
Completion
Development well
Differential
Drilled but Uncompleted Well
(DUC)
Definition
A depression in the Earth's crust formed from plate tectonics providing accommodation space for the
accumulation of sedimentary rocks and organic material. When subjected to the appropriate depth and
duration of burial, hydrocarbon generation can occur creating oil and natural gas bearing strata.
One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate
or NGLs.
One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six
Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or
price relationship between the commodities.
One Boe per day.
The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5
degrees Fahrenheit.
The process of treating a drilled well followed by the installation of permanent equipment for the
production of oil and natural gas, or in the case of a dry hole, the reporting of abandonment to the
appropriate agency.
A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic
horizon known to be productive.
An adjustment to the price of oil or natural gas from an established spot market price to reflect
differences in the quality and/or location of oil or natural gas.
A well that an operator has spud but has not yet begun hydraulic fracturing or completion operations.
Gross acres or gross wells
The total acres or wells, as the case may be, in which a mineral or royalty interest is owned.
MBbl
MBoe
Mcf
Mcf/d
MMBtu
MMcf
One thousand barrels of crude oil, condensate or NGLs.
One thousand Boe.
One thousand cubic feet of natural gas.
One Mcf per day.
One million British thermal units.
One million cubic feet of natural gas.
Net royalty acre
Mineral ownership standardized to a 12.5%, or 1/8th, royalty interest.
Net well
NGLs
NYMEX
Operator
Possible reserves
Probable reserves
Prospect
Proved developed reserves
The percentage of net revenue interest an owner has out of a gross well. For example, an owner who has
an 25% royalty interest in a single well owns 0.25 net wells.
Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas
and natural gasoline.
The New York Mercantile Exchange.
The individual or company responsible for the development and/or production of an oil or natural gas
well or lease.
Reserves that are less certain to be recovered than probable reserves.
Reserves that are less certain to be recovered than proved reserves but that, together with proved
reserves, are as likely as not to be recovered.
A specific geographic area that, based on supporting geological, geophysical or other data and also
preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential
for the discovery of commercial hydrocarbons.
Proved reserves that can be expected to be recovered through existing wells with existing equipment and
operating methods or in which the cost of the required equipment is relatively minor compared with the
cost of a new well or through installed extraction equipment and infrastructure operational at the time of
the reserves estimate if the extraction is by means not involving a well.
4
Term
Proved reserves
Proved undeveloped reserves
or PUDs
Realized price
Reserves
Reservoir
Royalty
Definition
Those quantities of oil, natural gas and NGLs that, by analysis of geoscience and engineering data, can
be estimated with reasonable certainty to be economically producible—from a given date forward, from
known reservoirs, and under existing economic conditions, operating methods and government
regulations—prior to the time at which contracts providing the right to operate expire, unless evidence
indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods
are used for the estimation. The project to extract the hydrocarbons must have commenced or the
operator must be reasonably certain that it will commence the project within a reasonable time. For a
complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-
X, Rule 4-10(a)(22).
Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for recompletion. The following rules apply to
PUDs: (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing
areas that are reasonably certain of production when drilled, unless evidence using reliable technology
exists that establishes reasonable certainty of economic producibility at greater distances; (ii) Undrilled
locations can be classified as having undeveloped reserves only if a development plan has been adopted
indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify
a longer time; and (iii) Under no circumstances shall estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by actual projects in the
same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing
reasonable certainty.
The cash market price less all applicable deductions
adjustments.
dd
such as quality,
transportation and demand
Estimated remaining quantities of oil and natural gas and related substances anticipated to be
economically producible, as of a given date, by application of development projects to known
accumulations. In addition, there must exist, or there must be a reasonable expectation that there will
exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil
and natural gas or related substances to market and all permits and financing required to implement the
project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing,
faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should
not be assigned to areas that are clearly separated from a known
accumulation by a non-
productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such
areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered
accumulations).
kk
A porous and permeable underground formation containing a natural
accumulation of producible oil and/
or natural gas that is confined by impermeable rock or water barriers and is individual and separate from
other reservoirs.
t
An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the
production from the leased acreage (or of the proceeds from the sale thereof), but does not require the
owner to pay any portion of the production or development costs on the leased acreage. Royalties may be
either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease
is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection
with a transfer to a subsequent owner.
Spot market price
The cash market price without reduction for expected quality, transportation and demand adjustments.
Spud
Commenced drilling operations on an identified location.
Undeveloped acreage
Lease acreage on which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil, natural gas or NGLs regardless of whether such acreage
contains proved reserves.
5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
The information in this Annual Report includes “forward-looking statements.” All statements, other than statements of
t, included in this Annual Report regarding our strategy, future operations, financial position, estimated revenues
historical facff
and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. In particular, our
statements regarding the ongoing COVID-19 pandemic and its expected impact on our business, financial position, results of
operations and cash flows are forward-looking statements. When used in this Annual Report, the words “may,” “could,”
“believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions and the negative of such words and
similar expressions are intended to identify forward-looking statements, although not all forward-looki
ng statements contain
such identifying words. These forward-looking statements are based on management’s current expectations and assumptim ons
about future events and are based on currently available information as to the outcome and timing of future events. Such
those projected.
statements may be influenced by factors that could cause actual outcomes and results to differ materially fromff
rs and other cautionary statements
When considering forward-looking statements, you should keep in mind the risk facto
described under the heading “Item 1A—Risk Factors” included in this Annual Report as well as the risk facto
rs and other
ff
cautionary statements contained in our other filff ings with the United States Securities and Exchange Commission (the "SEC").
ff
ff
The following importa
m
nt factors, in addition to those discussed elsewhere in this Annual Report, could affect the future
results of the energy industry in general, and our company in particular, and could cause actual results to differ materially fromff
those expressed in such forward-looking statements:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
our ability to execute on our business objectives;
the effecff
t of changes in commodity prices;
the level of production on our properties;
risks associated with the drilling and operation of oil and natural
t
gas wells;
the availabila
ity or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;
legislative or regulatory actions pertaining to hydraulic fraff cturing,
t
including restrictions on the use of water;
the availabila
ity of pipeline capaa
city and transportation facilities;
the effecff
t of existing and futuret
laws and regulatory actions;
the impact of derivative instruments;
conditions in the capital markets and our ability to obtain capital on favorablea
terms or at all;
the overall supply and demand for oil, natural gas and NGLs, and regional supply and demand factors, storage
availability, delays, or interruptions of production, including voluntary shut-ins;
operator budget constraints and their abia lity to obtain capia tal on favff orable terms or at all;
the actions of the Organization of Petroleum Exporting Countries ("OPEC") and other significant producers and
governments and the ability of such producers to agree to and maintain oil price and production controls;
competition from others in the energy industry;
the impact of reduced drilling activity in our focus areas and uncertainty as to whether development projects will
be pursued;
global or national health events, including the ongoing outbreak and resulting economic effects of the COVID-19
pandemic;
ff
the effect
(Creek) Nation reservation in Eastern Oklahoma and similar ruli
s of current or futuret
rr
litigation, including the recent U.S. Supreme Court ruling involving the Muscogee
ngs regarding reservations;
uncertainty of estimates of oil and natural
t
gas reserves and production;
the cost of developing the oil and natural gas underlying our properties;
our ability to replace our oil, natural gas and NGL reserves;
our ability to identify, complete and integrate acquisitions;
title defects in the properties in which we invest;
6
•
•
the cost of inflation;
technological advances;
• weather conditions, natural disasters and other matters beyond our control;
•
•
•
general economic, business, political or industry conditions; and
certain factors discussed elsewhere in this Annual Report.
Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions
prove incorrect, our actual results and plans could differ materially fromff
those expressed in any forward-looking statements.
Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not
tors on our business or the extent to
possible for our management to predict all risks, nor can we assess the impact of all facff
which any factor, or combination of factors, may cause actual results to differ materially fromff
those contained in any forward-
looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by
the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans,
intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those
anticipated or implied in the forward-looking statements.
Reserve engineering is a process of estimating underground accumulations of oil and natural
gas that cannot be measured
in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data
and price and cost assumptim ons made by reserve engineers. In addition, the results of drilling, testing and production activities
may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any
further production and development drilling. Accordingly, reserve estimates may differ significantly fromff
the quantities of oil,
t
natural
gas and NGLs that are ultimately recovered.
t
All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their
entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent
written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by
applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the
statements in this section, to reflect events or circumstances after the date of this Annual Report.
7
Item 1.
Business
PART I
requires, refee rences in this aii
otherwiseii
,”yy
CC
“Company
“Brigham LLC” referff
e
contextee
Unless thett
“we,” “our,” “us” or like terms referff
“Brigham Minerals,ll ” thett
Refee rences to thett
i
to Brigham
as the sole managing member of, Brigham LLC. BCC
which wholly oll wns Brigham Minerals, LLC and Rearden Minerals, LLC (collectively, tyy hett
Brigham Resources’ sole material assets.
o
) t”
e
to Brigham Minerals, Inc. and its stt
ubsidiaries.
righam Minerals owns an interest in, and actstt
righam LLC wholly oll wns Brigham Resources, LLC (“Brigham Resources”),
“Minerals Subsidiaries”), which are
on Form 10-K (the “Annual Report”
Minerals Holdings, LLC. BCC
nnual report
ed its i
completm
tt nitial public offo ering
On April 17, 2019, the Company
m
par value $0.01 per share (the “Class A common stock”). Unless indicated otherwise or the contextee
e
references in this Aii
operations (including reserves, production and acreage) oe
of Brigham Resources Operating, LLC (“Brigham
tt
periods after completion of the IPO, rO efer to the assets and operations of Brigham Minerals and its stt
Brigham LLC, BCC righam Resources and the Minerals Subsidiaries.
(the “IPO”) of shares of io ts Class A common stock,kk
requires,
(i) for periods prior to completion of the IPO, rO efer to the assets and
righam Resources, excee luding the historical results and operations
he IPO, aO nd (ii) f
i orff
ubsidiaries, including
Operating”), which was spun out in connection with t
to the Company
nnual Report
otherwiseii
f Bo
m
i
ff
Overview
We formed our company in 2012 to acquire and actively manage a portfolio of mineral and royalty interests in the core of
what we view as the most active, highly economic, liquids-rich resource plays across the continental United States. Our primary
business objective is to maximize risk-adjusted total returnt
ng growth in free cash floff w fromff
the continued organic development of our existing horizontal well inventory of 721 gross drilled but uncompleted horizontal
wells ("DUCs"), 755 gross permits and 13,496 gross undeveloped locations, all of which are unburdened by development
al expenditures or lease operating expenses, as well as leveraging our highly experienced technical evaluation team to
capita
continue to execute upon
our scalable business model of sourcing, methodically evaluating and integrating accretive minerals
acquisitions in the core of top-tier, liquids-rich resource plays.
to our shareholders by both capturi
u
a
Our portfolio is comprised of mineral and royalty interests across six of the most highly economic, liquids-rich resource
plays in the continental United States, including the Delaware and Midland Basins in the Permian Basin in West Texas and
New Mexico, the SCOOP and STACK plays in the Anadarko Basin in Oklahoma, the Denver-Julesburg (“DJ”) Basin in
Colorado and Wyoming and the Williston Basin in North Dakota. Our highly technical approa
ch towards mineral acquisitions
in the geologic core of top-tier resource plays has purposefully led to a concentrated portfolio covering 37 of the most highly
active counties for horizontal drilling in the continental United States.
a
Since inception, we have executed on our technically driven, financially disciplined acquisition approach and have closed
1,632 transactions with third-party mineral and royalty interest owners as of December 31, 2020. We have increased our
mineral and royalty interests from approximately 10,200 net royalty acres as of December 31, 2013, to approximately 86,285
net royalty acres as of December 31, 2020, which represents a 36% compound annual growth rate in our mineral and royalty
interests over that period. See “—Overview—Our Mineral and Royalty Interests” forff
a discussion of how we calculate net
royalty acres.
The following tablea
summarizes certain information regarding our net royalty acreage acquisitions during each year of
our operations.
Net Royalty Acres (NRAs)
Acquired
Number of Acquisitions
Average NRAs per Acquisition
NRAs at Period End
YoY% Change
2012
2013
2014
2015
2016
2017
2018
2019
2020
Total
500
9,700
17,300
7,200
9,800
9,400
14,900
13,400
4,085
15
33
313
31
380
46
152
47
121
81
153
61
201
74
216
62
81
50
86,285
1,632
53
500
10,200
27,500
34,700
44,500
53,900
68,800
82,200
86,285
86,285
— 1,940 %
170 %
26 %
28 %
21 %
28 %
19 %
5 %
During 2020, our producing well count grew by 1,077 gross horizontal wells largely through acquisitions and the
conversions of our DUC and permitted locations, representing an increase of 22% from December 31, 2019. In addition to this
activity, 381 gross horizontal wells were spud on our mineral and royalty interests. This development has translated into
production growth with our production volumes growing approximately 28% for the year ended December 31, 2020 as
compared to the year ended December 31, 2019. Further, our production volumes are comprised of high-value liquids with 72%
of our volumes for the year ended December 31, 2020 composed of crude oil and NGLs, which represents 88% of our mineral
8
and royalty revenues for the period. We expect to see near term organic conversion of our asset fromff
721 gross DUCs across
our interests and 755 gross horizontal drilling permits as of December 31, 2020, all of which are unburdened by additional
al expenditure outlays. Quarterly gross and net wells spud on our minerals have rebounded since the second quarter of
capita
to the dramatic curtailment in operator activity as a result of COVID-19 and
2020, which was the low point during the year dued
the actions of OPEC, Russia, and other oil and gas producing countries ("OPEC+") during March 2020, both of which
contributed to a dramatic decline in commodity prices during the first half of 2020. The chart below depicts historical gross
and net wells spud on our acreage:
Average Quarterly Wells Spud on Acreage
Gross Spuds
Net Spuds
400
350
300
250
200
150
100
50
0
24848
2302300
214
2099
18585
208
150
99
82822
2
1.75
1.5
1.25
1
0.75
5757
363636
7979
0.5
0.25
0
1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20
Delaware
DJ Basin
Midland
Williston
SCOOP
Other
STACK
Net Spuds
In addition to existing near-term development through the drilling and completion of our DUCs and permits, we have a
further 13,496 gross undeveloped locations providing us with substantial long-term organic drilling inventory on our acreage.
Our Mineral and Royalty Interests
Mineral interests are real-property interests that are typically perpetual and grant both ownership of the oil, natural gas
and NGLs under a tract of land and the ability to lease development rights to a third party. When those rights are leased, usually
for a three-year primary term, we typically receive an upfront cash payment, known as lease bonus, and we retain a mineral
royalty, which entitles us to a percentage of production or revenue. In addition to mineral interests, which represented
approximately 94% of our net royalty acres as of December 31, 2020, we also own other similar types of interests, including
arrangement burdening
nonparticipating royalty interests and overriding royalty interests (“ORRIs”). ORRIs are a contractual
the working interest ownership of a lease and represent the right to receive a fixeff
d percentage of production or revenue from
production from a lease. ORRIs remain in effect until the associated lease expires and are therefore not perpetual in nature.
Approximately 5% of our mineral position is within current units that include Federal acreage managed by the Bureau of Land
Management.
t
t
As a mineral and royalty interest owner, we incur the initial cost to acquire our interests, but thereafter do not incur any
development capita
al expenditures or lease operating expenses, which are entirely borne by the operator. Mineral and royalty
owners only incur their proportionate share of severance and ad valorem taxes, as well as in some instances, gathering,
a mineral and royalty interest
transportation and marketing costs. As a result, operating margins and therefore free cash floff w forff
owner are higher as a percentage of revenue than forff
a traditional exploration and production operating company.
As of December 31, 2020, our mineral and royalty interests consisted of approxi
a
mately 61,000 net mineral acres, which
gas rights at a weighted average royalty of 17.7%.
have been leased to operators to explore for and develop our oil and natural
t
9
Typically, mineral owners standardize ownership to a 12.5% royalty, or 1/8th interest, which is referred to as a “net royalty
acre.” Our net mineral acres standardized to a 1/8th interest equate to approximately 86,285 net royalty acres. Our net mineral
acres standardized to a 100% royalty, or 8/8th basis, equate to approximately 10,790 “100% royalty acres.” Our approximately
86,285 net royalty acres are located within 1,691 drilling spacing units (“DSUs”), which are the areas designated in a spacing
order or unit designation as a drilling unit and within which operators drill wellbores to develop our oil and natural
gas rights.
Our DSUs, in aggregate, consist of a total of approximately 1,682,335 gross acres, which we refer to as our “gross DSU
acreage.” Within our gross DSU acreage, we expect to have an interest in wells currently producing or that will be drilled in the
summarizes our mineral and royalty interest position and the conversion of our interests between net
future. The following tablea
mineral acres, net royalty acres and 100% royalty acres as of December 31, 2020.
t
Net Mineral Acres
Weighted Average
Royalty
Net Royalty Acres(1)
100% Royalty
Acres(2)
Gross DSU Acres
Implied Average Net
Revenue Interest per
Well(3)
61,000
17.7 %
86,285
10,790
1,682,335
0.6 %
(1) Standardized to a 1/8th interest (i.e., 61,000 net mineral acres * 17.7% / 12.5%).
(2) Standardized to a 100% interest (i.e., 86,285 net royalty acres * 12.5%).
(3) Calculated as number of 100% royalty acres per gross DSU acre (i.e., 10,790 100% royalty acres /1,682,335 gross DSU acres).
Our Properties
Focus Areas
Our mineral and royalty interests are primarily located in six resource plays, which we referff
to as our focus areas. These
include the Delaware and Midland Basins in the Permian Basin, the SCOOP and STACK plays in the Anadarko Basin, the DJ
Basin and the Williston Basin. The following chart shows our overall exposure to each of our primary focus areas based on our
net royalty acres in each focff us area as of December 31, 2020.
Other
8%
Williston
9%
Delaware
33%
DJ
18%
(cid:27)(cid:25)(cid:15)(cid:21)(cid:27)(cid:24)
(cid:49)(cid:53)(cid:36)
Midland
6%
STACK
13%
SCOOP
13%
In addition, the following tabla e summarizes certain information regarding our primary focus areas. Our average daily net
production for the year ended December 31, 2020 was comprised 53% of oil production, 27% of natural
20% of NGL production.
t
gas production and
10
Acreage as of December 31, 2020
Resource Play/Basin
Net
Mineral
Acres
Weighted
Average
Royalty
Net
Royalty
Acres(1)
100%
Royalty
Acres(2)
Delaware
Midland
SCOOP
STACK
DJ
Williston
Other
Total
18,375
4,175
7,750
7,625
12,325
6,175
4,575
61,000
19.3 %
15.6 %
18.4 %
17.6 %
16.1 %
16.1 %
18.1 %
17.7 %
28,330
5,220
11,400
10,725
15,890
7,950
6,770
3,540
650
1,430
1,340
1,990
990
850
Gross
DSU
Acres
345,770
123,815
208,455
179,960
174,535
503,455
146,345
86,285
10,790
1,682,335
Implied
Average
Net
Revenue
Interest
per
Well(3)
Gross
Horizontal
Producing
Well Count
as of
December
31, 2020(4)
Average
Daily Net
Production
for the year
ended
December
31, 2020(5)
(Boe/d)
Average Daily
Net
Production
for the
quarter ended
December 31,
2020(5) (Boe/
d)
1.0 %
0.5 %
0.7 %
0.7 %
1.1 %
0.2 %
0.6 %
0.6 %
1,305
459
563
415
1,211
1,833
199
5,985
4,741
645
1,112
875
1,307
729
74
9,483
4,720
712
1,122
770
1,196
780
61
9,361
Note: Individual amounts may not add up to totals due to rounding.
(1) Standardized to a 1/8th interest.
(2) Standardized to a 100% interest.
(3) Calculated as number of 100% royalty acres per gross DSU acre.
(4) Represents number of horizontal producing wells across all DSUs in which we participate.
(5) Represents actual production plus allocated accrued volumes attributable to the period presented.
Permian Basin-Delaware and Midland Basins
The Permian Basin ranges fromff
West Texas into southeastern New Mexico and is currently the most active area forff
horizontal drilling in the United States. The Permian Basin is furthe
r subdivided into the Delaware Basin in the west and the
ff
Midland Basin in the east. Based on our geologic and engineering data as well as current delineation efforts by operators, we
believe our mineral and royalty interests in the Delaware Basin are prospective for seven or more producing zones of economic
horizontal development including the Wolfcamp A, B, C and XY; First, Second and Third Bone Spring; and the Avalon. Our
Delaware Basin mineral and royalty interests are located in Reeves, Loving, Ward, Pecos, Culberson and Winkler Counties,
Texas with our remaining interests located in Lea and Eddy Counties, New Mexico. Based on our geologic and engineering
interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the Midland
Basin are prospective for five or more producing zones of economic horizontal development including the Middle Spraberry;
Lower Spraberry; and Wolfcamp A, B, C, and D / Cline. Our Midland Basin mineral and royalty interests are located in Martin,
Midland, Upton, Howard, Glasscock and Reagan Counties, Texas.
Anadarko Basin-SCOOP and STACK PCC
laysa
The SCOOP play (South Central Oklahoma Oil Province) is located in central Oklahoma in Grady, Garvin, Stephens and
McClain Counties. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we
believe our mineral and royalty interests in the SCOOP play are prospective for two or more producing zones of economic
horizontal development including multiple Woodford benches and the Springer Shale. In addition, operators are also currently
testing other forma
red to as SCORE (Sycamore
Caney Osage Resource Expansion). The STACK play (derived from Sooner Trend Anadarko Basin Canadian and Kingfisher
Counties) is located in central Oklahoma in Kingfisher, Canadian, Caddo and Blaine Counties. Based on our geologic and
engineering data as well as current delineation efforts by operators, we believe our mineral and royalty interests in the STACK
play are prospective for two or more producing zones of economic horizontal development including multiple benches within
both the Meramec and Woodford formations.
tions in the area including the Sycamore, Caney and Osage, which is also referff
ff
DJ Basin
The DJ Basin is located in Northeast Colorado and Southeast Wyoming, with the majora
ity of operator horizontal drilling
activity located in Weld and Broomfield Counties, Colorado, and Laramie County, Wyoming. Based on our geologic and
engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the
DJ Basin are prospective for four or more producing zones of economic horizontal development including the Niobrara A, B
and C and Codell formff
ations.
11
ii
Williston
Basin
The Williston Basin stretches fromff
western North Dakota into eastern Montana with the majora
ity of operator horizontal
drilling activity located in Mountrail, Williams, and McKenzie Counties, North Dakota. Based on our geologic and engineering
interpretations as well as current operator delineation efforts, we believe our mineral and royalty interests are prospective for
two or more producing zones of economic horizontal development including the Bakken and multiple Three Forks benches.
The majora
ity of our interests are located in Mountrail, Williams and McKenzie Counties with additional interests owned in
Divide, Burke, Dunn, Billings and Stark Counties, North Dakota and Richland County, Montana.
Other Counties
Our other interests are comprised of mineral and royalty interests owned in Carter and Love Counties, Oklahoma in what
we refer to as the Extended Woodford play in the Marietta and Ardmore Basins. We also own acreage in the Merge trend in
Oklahoma, centered in northern Grady County and southern Canadian Counties.
Prospectivtt e UndeUU
veloped HorizHH ontal Drillingll
Locations
As of December 31, 2020, we have identified 13,496 gross proved, probable and possible drilling locations across our
gross DSU acreage as identified in our December 31, 2020 reserve report audited by Cawley, Gillespie & Associates, Inc.
("CG&A"), our independent petroleum engineering firm. Furthermore, we believe additional optionality is possible through the
delineation of additional formations as well as incremental wells in existing formations. Approximately 51% of our total net
horizontal undeveloped locations are located in the Delaware and Midland Basins, with another 19% located in the SCOOP and
.
STACK plays of the Anadarko Basin in Oklahoma, as shown in the following tablea
Delaware Basin
Midland Basin
SCOOP
STACK
DJ Basin
Williston
Other
Total
Gross
Horizontal
Undeveloped
Locations
5,201
1,666
1,055
1,491
1,584
1,591
908
Percentage of
Total Portfolio
38 %
12 %
8 %
11 %
12 %
12 %
7 %
Net Horizontal
Undeveloped
Locations
Percentage of
Total Portfolio
54.7
10.7
8.3
13.3
20.2
3.1
6
47 %
9 %
7 %
11 %
17 %
3 %
5 %
13,496
100 %
116.3
100 %
Note: Individual amounts may not total due to rounding.
Additionally, the following tablea
provides a detailed summary of our inventory of horizontal drilling locations as of
December 31, 2020.
12
Productive Horizons
Delaware Basin
Wolfcamp A
Wolfcamp B
3rd BS/WC XY
2nd Bone Spring
Avalon
Other
Total
Midland Basin
Wolfcamp A
Wolfcamp B
Lower Spraberry
Other
Total
SCOOP
Woodford
Springer
Total
STACK
Woodford
Meramec
Total
DJ Basin
Niobrara
Codell
Total
Williston Basin
Bakken
Three Forks
Total
Other
Grand Total
Gross Horizontal
Undeveloped
Locations(1)
Total Gross
Horizontal
Locations(2)
DSUs(3)(4)
Gross Horizontal
Undeveloped
Locations Per
DSU(4)
Total Gross
Horizontal
Locations Per
DSU(4)
Net Horizontal
Undeveloped
Locations(5)
2,085
1,155
710
602
153
496
5,201
477
421
522
246
1,666
758
297
1,055
777
714
1,491
1,185
399
1,584
725
866
1,591
908
13,496
2,842
1,378
1,054
675
188
556
6,693
684
663
701
295
2,343
1,276
404
1,680
901
1,008
1,909
2,192
712
2,904
1,838
1,710
3,548
1,125
20,202
454
408
330
216
67
195
457
141
141
141
93
142
187
100
187
171
189
189
190
149
191
360
360
363
162
1,691
4.6
2.8
2.2
2.8
2.3
2.5
11.4
3.4
3
3.7
2.6
11.7
4.1
3
5.6
4.5
3.8
7.9
6.2
2.7
8.3
2
2.4
4.4
5.6
8
6.3
3.4
3.2
3.1
2.8
2.9
14.6
4.9
4.7
5
3.2
16.5
6.8
4
9
5.3
5.3
10.1
11.5
4.8
15.2
5.1
4.8
9.8
6.9
11.9
23.2
13
6.8
4.8
0.8
6.1
54.7
3
2.7
3.2
1.8
10.7
6.1
2.2
8.3
6.9
6.4
13.3
15.1
5.1
20.2
1.4
1.8
3.1
6
116.3
(1) Represents gross undeveloped horizontal drilling locations across our gross DSU acreage
(2) Includes all wells in each horizon, including PDP, DUC, permitted and unpermitted locations.
(3) Represents the aggregate number of DSUs covering any of the applicable productive horizons as identified in the reserve report.
(4) The number of DSUs in each horizon and locations per DSU in each horizon do not total due to differing prospectivity of each horizon across each DSU
(i.e., not all horizons are booked in all DSUs).
(5) A net well represents 100% net revenue interest in a single gross well.
Third-Pii
artyPP
Operatorsrr
Beyond our technical analysis to identify core, highly economic geologic areas, an additional critical aspect of our
evaluation process is to acquire mineral and royalty interests that will be drilled and completed by operators we believe will
outperform their peers through the application of the latest drilling and completion technologies in each of our focus areas. The
following chart summarizes our exposure to these operators based on the percentage of our net interests in the wells to be
drilled by each operator. Net interests per gross location are normalized to 7,500 ft. laterals.
13
OXY
13%
Other Private
14%
Other Public
6%
CVX
8%
OVV
5%
PXD
5%
CLR
5%
RDS
4%
BATL
2%
Camino
2%
XOG
2%
PDCE
2%
WLL
3%
EOG
3%
CPE
3%
PRI
3%
XEC
4%
COP
3%
FANG
3%
DVN
4%
MRO
4%
XOM
4%
In addition, the following tablea
shows our exposure to each of these operators broken down by our primary focus areas
based on the percentage of our net interests in the wells to be drilled by each operator as of December 31, 2020.
Operator
Occidental Petroleum
Chevron Corp.
Ovintiv, Inc.
Pioneer Natural Resources
Continental Resources
Royal Dutch Shell
Devon Energy
Marathon
Exxon Mobil Corp.
Cimarex
Diamondback Energy
ConocoPhillips
PRI Operating
Callon Petroleum
EOG Resources
Whiting Petroleum
PDC Energy
Extraction Oil and Gas
Battalion Oil
Camino
Subtotal
Other Operators
Total
Total
Portfolio
13 %
8 %
5 %
5 %
5 %
4 %
4 %
4 %
4 %
4 %
3 %
3 %
3 %
3 %
3 %
3 %
2 %
2 %
2 %
2 %
80 %
20 %
100 %
Percentage as of December 31, 2020
Delaware
Midland
SCOOP
STACK
DJ Basin
Williston
Other
22 %
10 %
— %
1 %
— %
10 %
3 %
1 %
6 %
6 %
6 %
4 %
6 %
6 %
1 %
— %
1 %
— %
4 %
1 %
87 %
13 %
1 %
4 %
3 %
47 %
— %
— %
— %
— %
4 %
— %
5 %
8 %
— %
— %
— %
— %
— %
— %
— %
— %
72 %
28 %
— %
— %
26 %
— %
37 %
— %
— %
20 %
— %
— %
— %
— %
— %
— %
— %
— %
— %
— %
— %
2 %
85 %
15 %
— %
— %
21 %
— %
3 %
— %
26 %
17 %
— %
9 %
— %
— %
— %
— %
— %
— %
— %
— %
— %
— %
75 %
25 %
17 %
15 %
— %
— %
— %
— %
— %
— %
— %
— %
— %
— %
— %
— %
11 %
13 %
10 %
12 %
— %
— %
78 %
22 %
— %
— %
5 %
— %
21 %
— %
— %
1 %
5 %
— %
— %
12 %
— %
— %
3 %
3 %
— %
— %
— %
— %
50 %
50 %
— %
— %
12 %
— %
22 %
— %
2 %
4 %
14 %
3 %
— %
— %
— %
— %
— %
— %
— %
— %
— %
21 %
77 %
23 %
100 %
100 %
100 %
100 %
100 %
100 %
100 %
Note: Individual amounts may not add up to totals due to rounding.
Business Objectives
Our primary business objective is to deliver an attractive risk-adjusted total returt n t
o our shareholders through (i) the
organic growth of our free cash floff w generated from our existing portfolio of approximately 86,285 net royalty acres, and
r
14
(ii) the continued sourcing and execution of accretive mineral acquisitions in the core of highly economic, liquids-rich resource
plays.
Our Corporate Structure
Brigham Minerals, Inc. was incorporated as a Delaware corporation in June 2018 for the purpose of completing the IPO
and related transactions. On April 23, 2019, in connection with the IPO, Brigham Minerals became a holding company whose
sole material asset consists of units in Brigham LLC (the “Brigham LLC Units”). Brigham LLC wholly owns Brigham
Resources, which wholly owns the Minerals Subsidiaries, which own all of our operating assets. The remainder of the Brigham
LLC Units are held by affiliates of Yorktown Partners LLC (“Yorktown”) and Pine Brook Road Advisors, LP (“Pine Brook”)
and certain of our management members and other prior investors (together with Yorktown and Pine Brook, the “Original
Owners”).
As the sole managing member of Brigham LLC, Brigham Minerals operates and controls all of the business and affairs of
Brigham LLC, and through Brigham LLC and its subsidiaries, conducts its business. As a result, we consolidate the financial
results of Brigham LLC and its subsidiaries and report temporary equity related to the portion of Brigham LLC Units not owned
by us, which will reduce net income (loss) attributablea
to the holders of our Class A common stock. As of February 19, 2021,
Brigham Minerals owned 76.8% of Brigham LLC.
Each of the Original Owners holds one share of our Class B common stock, par value $0.01 per share (the "Class B
common stock"), for each Brigham LLC Unit such person holds. Each share of Class B common stock has no economic rights
but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A common stock and
Class B common stock vote together as a single class on all matters presented to our shareholders for their vote or approval,
icable law or by our amended and restated certificate of incorporation. We do not intend to
except as otherwise required by appl
list our Class B common stock on any exchange.
a
ff
Under the First Amended and Restated Limited Liability Company Agreement of Brigham LLC (the “Brigham LLC
Agreement”), each holder of a Brigham LLC Unit (a “Brigham Unit Holder”) has, subject to certain limitations, the right (the
“Redemption Right”) to cause Brigham LLC to acquire all or a portion of its Brigham LLC Units for,
at Brigham LLC’s
election, (i) shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each Brigham
LLC Unit redeemed, subjeu
ct to conversion rate adjustments for stock splits, stock dividends and reclassification and other
similar transactions or (ii) an equivalent amount of cash. Our decision to make a cash payment upon a Brigham Unit Holder’s
redemption election must be made by our independent directors (within the meaning of the New York Stock Exchange and
Section 10A-3 of the Securities Act) who do not own Brigham LLC units that are subject to such redemption. We will
determine whether to issue shares of Class A common stock or cash based on facts in existence at the time of the decision,
which we expect would include the relative value of the Class A common stock (including trading prices for the Class A
ity of other sources of liquidity (such as an issuance of
common stock at the time), the cash purchase price, the availabila
preferred stock) to acquire the Brigham LLC Units and alternative uses for such cash. Alternatively, upon the exercise of the
Redemption Right, Brigham Minerals (instead of Brigham LLC) will have the right (the “Call Right”) to, for administrative
convenience, acquire each tendered Brigham LLC Unit directly frff om the redeeming Brigham Unit Holder for, at its election,
(x) one share of Class A common stock or (y) an equivalent amount of cash. In connection with any redemption of Brigham
LLC Units pursuant to the Redempm tion Right or acquisition pursuant to our Call Right, the corresponding number of shares of
Class B common stock will be cancelled. Under the Registration Rights Agreement we entered into with certain of the Original
Owners in connection with the IPO, such Original Owners have the right, under certain circumstances, to cause us to register
the offer and resale of their shares of Class A common stock.
The following diagram indicates our simplified ownership structuret
illustrative purposes only and does not represent all legal entities affiliated with us.
as of February 19, 2021. This chart is provided forff
15
(1)
(2)
Public stockholders include shares of Class A common stock sold to the public, issued pursuant to awards granted under our 2019
Long Term Incentive Plan ("LTIP") or issued to Brigham Unit Holders in connection with their exercise of the Redemption Right.
Legacy Brigham Unit Holders include members of our management team and investors in our Company prior to our IPO (other than
our Sponsors) who continue to hold Brigham LLC Units. Certain of the interests of our management in Brigham LLC are held
indirectly through Brigham Equity Holdings, LLC. Brigham Equity Holdings, LLC directly owns 141,820 Brigham LLC Units,
representing an approximate 0.3% interest in Brigham LLC. Total voting power does not include any shares of Class A common stock
held by such legacy Brigham Unit Holders.
Our Principal Stockholders
We have valuable relationships with Yorktown and Pine Brook, private investment firms focff used on investments in the
energy sector. As of February
19, 2021, affiliates of Yorktown and Pine Brook (collectively, our “Sponsors”) own no shares of
Class A common stock and 9,603,597 shares of Class B common stock representing approximately 16.9% of the voting power
of Brigham Minerals and 9,603,597 Brigham LLC Units.
rr
16
Principal Executive Offices
Our principal executive offices are located at 5914 W. Courtyard Drive, Suite 200, Austin, Texas 78730, and our
telephone number at that address is (512) 220-6350.
Our website address is www.brighamminerals.com. We make our periodic reports and other information filed with or
furnished to the SEC available free of charge through our website as soon as reasonably practicablea
after those reports and other
information are electronically filed with or furnished to the SEC. Information on our website or any other website is not
incorporated by reference into, and does not constitute a part of, this Annual Report.
Proved, Probable and Possible Reserves
Oil, Natural Gas and NGLs Data
Evaluation and Audit of Po
roved, Probable and Possible Reserves. Our proved, probable and possible reserve estimates as
of December 31, 2020, 2019 and 2018 were audited by CG&A, our independent petroleum engineers. Within CG&A, the
th in the reserve reports incorporated herein is
technical person primarily responsible for preparing the reserve estimates set forff
Todd Brooker. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron
USA. Mr. Brooker has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations,
fair market valuations, field studies, pipeline resource studies and acquisition/divestituret
analysis. His reserve reports are
routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and
unconventional resources in every majora U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane
fields, waterfloods and complex, faulted structures.
Mr. Brooker graduated with honors from the University of Texas at Austin
in 1989 with a Bachelor of Science degree in Petroleum Engineering and is a registered Professional Engineer in the State of
Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers (SPEE).
t
Mr. Brooker meets or exceeds the requirements with regard to qualifications,
independence, objectivity and
confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information
promulgated by the Society of Petroleum Engineers. CG&A does not own an interest in any of our properties, nor is it
employed by us on a contingent basis. A summary of CG&A’s report with respect to our proved, probable and possible reserve
estimates as of December 31, 2020 is included as an exhibit to this Annual Report.
We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our
independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved, probable
and possible reserves relating to our properties. Our internal technical team members meet with our independent reserve
engineers periodically during the period covered by the proved, probable and possible reserve report to discuss the assumptim ons
and methods used in the proved, probable and possible reserve estimation process. We provide historical information to CG&A
gas production, well test data, commodity prices and our estimates
for our properties, such as ownership interest, oil and natural
of our operators’ operating and development costs. Hamilton Hogsett is primarily responsible for overseeing the preparation of
our reserve estimates. Mr. Hogsett has substant
ial reservoir and operations experience having worked as a petroleum engineer
since 2009 and is supported by our engineering and geoscience staff. Prior to joining our Company in 2017, Mr. Hogsett
worked at Apache Corporation and Antero Resources Corporation.
u
t
The preparation of our proved, probable and possible reserve estimates was completed in accordance with our internal
control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
•
•
•
•
•
review and verification of historical production data, which data is based on actual production as reported by our
operators;
review by Mr. Hogsett, our Vice President of Reservoir Engineering, of all of our reported proved, probable and
possible reserves, including the review of all significant reserve changes and all PUD additions or reductions;
ff
verificatio
n of property ownership by our land department;
review of reserve estimates by Mr. Hogsett or under his direct supervision; and
direct reporting responsibilities by Mr. Hogsett to our Chief Executive Officer.
Estimation of Proved Reserves. In accordance with ruler
to companies involved in
oil and natural
gas, which, by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date
forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The
gas producing activities, proved reserves are those quantities of oil and natural
s and regulations of the SEC applicablea
t
t
17
t
t
oil and natural
term “reasonable certainty” means deterministically, the quantities of oil and/or natural
gas are much more likely to be achieved
than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the
estimate. All of our proved reserves as of December 31, 2020, 2019 and 2018 were estimated using a deterministic method. The
estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of
recoverablea
gas and the second determination results in the estimation of the uncertainty associated with those
estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of
recoverablea
reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into
four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii)
volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator
in the process of estimating the quantities of reserves. Reserves forff
proved developed producing wells were estimated using
production performance methods for the vast majority of properties. Certain new producing properties with very little
production history were forecast using a combination of production performance and analogy to similar production, both of
which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and
undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for
predicting proved developed non-producing and PUDs for our properties, due to the abundance of analog data.
To estimate economically recoverablea
tors and
assumptim ons, including the use of reservoir parameters derived from geological and engineering data that cannot be measured
directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of futuret
proved reserves and related future net cash flows, we considered many facff
production rates.
Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual
technology that
production from projects in the same reservoir or an analogous reservoir or by other evidence using reliablea
shes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational
establia
tested and have been demonstrated to provide reasonably certain results with consistency and
methods) that have been fieldff
sh reasonable certainty with respect to
repeatability in the formation being evaluated or in an analogous formation. To establia
our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been
demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole
completion information, geologic data, electrical logs, radioactivity logs, core data, and historical well cost and operating
expense data.
Estimation of Probable Reserves. Estimates of probable reserves are inherently imprecise. When producing an estimate of
the amount of oil, natural
from a particular reservoir, an estimated quantity of probable
reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together
with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to
revisions based on production history, results of additional exploration and development, price changes and other factors.
gas and NGLs that is recoverablea
t
t
t
oil and natural
oil and natural
When deterministic methods are used, it is as likely as not that actuat
l remaining quantities recovered will exceed the sum
of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that
the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. All of our probable reserves as
of December 31, 2020, 2019 and 2018 were estimated using a deterministic method, which involves two distinct
determinations: an estimation of the quantities of recoverablea
gas and an estimation of the uncertainty associated
with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the
quantities of recoverablea
gas reserves uses the same generally accepted analytical procedures as are used in
estimating proved reserves, namely production performance-based methods, material balance-based methods, volumetric-based
methods and analogy. In the case of probable reserves, the recoverabla e reserves cannot be said to have a “high degree of
confidence that the quantities will be recovered” but are “as likely as not to be recovered.” The lower degree of certainty can
come frff om several factors including: (1) direct offset production that does not meet an economic threshold, despite localized
averages that do meet that threshold, (2) an increased distance from offset production to the probable location of over one mile
but under three miles, (3) a perceived risk of communication or depletion from nearby producers, (4) a perceived risk of
attempting new drilling or completion technologies that have not been used in direct offset production or (5) an uncertainty
nced above, the lower
regarding geologic positioning that could affect recoverable reserves. When considering the factors refereff
degree of certainty of our probable reserves came from a combination of these factors depending upon the applicablea
basin.
Many of the probable locations assigned in our reserve reports had few uncertainties and resemble proved undeveloped
locations except for their distance from commercial production. Other probable locations had uncertainties related to not only
distance from commercial production, but also related to well spacing and development timing. In general, we did not book
probable locations if there was geologic uncertainty or if there was not commercial producd tion to support such locations.
Estimation of Possible Reserves. Estimates of possible reserves are also inherently imprecise. When producing an estimate
from a particular reservoir, an estimated quantity of possible
of the amount of oil, natural gas and NGLs that is recoverablea
18
reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of
possible reserves are also continually subject to revisions based on production history, results of additional exploration and
development, price changes and other facff
tors.
t
t
oil and natural
When deterministic methods are used, the total quantities ultimately recovered fromff
a project have a low probability of
exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10%
probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves
estimates. All of our possible reserves as of December 31, 2020, 2019 and 2018 were estimated using a deterministic method,
which involves two distinct determinations: an estimation of the quantities of recoverablea
gas and an estimation
of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules.
The process of estimating the quantities of recoverablea
gas reserves uses the same generally accepted analytical
oil and natural
procedures as are used in estimating proved reserves, namely production performance-based methods, material balance-based
methods, volumetric-based methods and analogy. In the case of possible reserves, the recoverablea
reserves cannot be said to be
“as likely as not to be recovered”, but “might be achieved, but only under more favorable circumstances than are likely.” The
lower degree of certainty can come fromff
tors including: (1) direct offset production that does not meet an economic
threshold, despite localized averages that do meet that threshold, (2) an increased distance from offset production to the possible
location of over one mile but under five miles, (3) a perceived risk of communication or depletion from nearby producers, (4) a
perceived risk of attempting new drilling or completion technologies that have not been used in direct offset production or (5)
reserves. When considering the factors referff enced
an uncertainty regarding geologic positioning that could affect recoverablea
above, the lower degree of certainty of our possible reserves came fromff
a combination of these factors depending upon the
applicable basin. Many of the possible locations assigned in our reserve reports had few uncertainties and resemble proved
undeveloped locations except for their distance from commercial production. Other possible locations had uncertainties related
to not only distance from commercial production, but also related to well spacing and development timing. In general, we did
not book possible locations if there was geologic uncertainty or if there was not commercial production to support such
location.
several facff
Summary of Reserves. The following table presents our estimated net proved, probable and possible reserves as of
December 31, 2020, 2019 and 2018, based on our proved, probable and possible reserve estimates as of such dates, which have
, by CG&A, our independent petroleum engineering firm, in accordance with the rules
been prepared or audited, as applicablea
and regulations of the SEC. All of our proved, probable and possible reserves are located in the United States.
19
Estimated proved developed reserves:
Oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Total (MBoe)
Estimated proved undeveloped reserves:
Oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Total (MBoe)
Estimated total proved reserves:
Oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Total (MBoe)
Estimated probable reserves:
Oil (MBbls) (4)
Natural gas (MMcf) (4)
NGLs (MBbls) (4)
Total (MBoe) (4)
Estimated possible reserves:
Oil (MBbls) (4)
Natural gas (MMcf) (4)
NGLs (MBbls) (4)
Total (MBoe) (4)
Oil and Natural Gas Prices:
Oil- WTI posted price per Bbl
Natural gas - Henry Hub spot price per MMbtu
Years Ended December 31,
2020 (1)
2019 (2)
2018 (3)
9,403
31,873
3,426
18,141
3,797
11,771
1,164
6,922
13,200
43,644
4,590
25,063
20,096
85,477
9,417
43,759
12,356
32,638
4,475
22,271
9,924
33,232
2,494
17,957
7,037
28,498
3,344
15,131
16,961
61,730
5,838
33,088
16,948
70,627
8,274
36,993
11,986
33,063
5,024
22,521
$
$
39.57
2.00
$
$
55.65
2.60
$
$
6,067
21,735
1,898
11,588
6,924
30,061
3,219
15,153
12,991
51,796
5,117
26,741
14,854
66,682
7,560
33,528
10,302
29,775
3,545
18,810
65.66
3.12
(1) Our estimated net proved, probable and possible reserves were determined using average first-day-of-the month prices for the prior 12 months in accordance
with SEC guidance. For oil and NGL volumes, the average West Texas Intermediate ("WTI") posted price of $39.57 per barrel as of December 31, 2020 was
adjusted for quality, transportation fees and a regional price differential. NGL prices varied by basin from 10% to 25% of the WTI posted price. For gas
volumes, the average Henry Hub spot price of $2.00 per MMBtu as of December 31, 2020 was adjusted for energy content, transportation fees and a regional
price differential. These prices do not give effect to derivative transactions and are held constant throughout the lives of the properties. The average adjusted
product prices weighted by production over the remaining lives of the properties are $36.35 per barrel of oil, $8.19 per barrel of NGL and $1.03 per Mcf of gas
as of December 31, 2020.
(2) Our estimated net proved, probable and possible reserves were determined using average first-day-of-the month prices for the prior 12 months in accordance
with SEC guidance. For oil and NGL volumes, the average WTI posted price of $55.65 per barrel as of December 31, 2019 was adjusted for quality,
transportation fees and a regional price differential. NGL prices varied by basin from 13% to 30% of the WTI posted price. For gas volumes, the average Henry
Hub spot price of $2.60 per MMBtu as of December 31, 2019 was adjusted for energy content, transportation fees and a regional price differential. All prices do
not give effect to derivative transactions and are held constant throughout the lives of the properties. The average adjusted product prices weighted by
production over the remaining lives of the properties are $51.01 per barrel of oil, $14.39 per barrel of NGL and $1.51 per Mcf of gas as of December 31, 2019.
(3) Our estimated net proved, probable and possible reserves were determined using average first-day-of-the-month prices for the prior 12 months in
accordance with SEC guidance. For oil and NGL volumes, the average WTI posted price of $65.66 per barrel as of December 31, 2018 was adjusted for
quality, transportation fees and a regional price differential. NGL prices varied by basin from 22% to 41% of the WTI posted price. For gas volumes, the
average Henry Hub spot price of $3.12 per MMBtu as of December 31, 2018 was adjusted for energy content, transportation fees and a regional price
differential. All prices do not give effect to derivative transactions and are held constant throughout the lives of the properties. The average adjusted product
prices weighted by production over the remaining lives of the properties are $61.31 per barrel of oil, $23.98 per barrel of NGL and $2.51 per Mcf of gas as of
December 31, 2018.
Reserve engineering is a subjective process of estimating volumes of economically recoverablea
gas that
cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and
of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results
the
of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ fromff
gas and of
quantities of oil and natural
gas that are ultimately recovered. Estimates of economically recoverablea
oil and natural
oil and natural
t
t
t
20
future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including
geologic interpretation, prices and futuret
production rates and costs. Please read “Item 1A—Risk Factors.”
Additional information regarding our proved, probable and possible reserves can be foun
d in the notes to our consolidated
financial statements included elsewhere in this Annual Report and the proved, probable and possible reserve reports as of
December 31, 2020 and December 31, 2019 and 2018, which are included as exhibits to this Annual Report.
ff
PUDs
As of December 31, 2020, we estimated our PUD reserves to be 3,797 MBbls of oil, 11,771 MMcf of natural
gas and
1,164 MBbls of NGLs, for a total of 6,922 MBoe. PUDs will be converted from undeveloped to developed as the applicable
wells begin production.
t
The following tablea
s summarize our changes in PUDs during the year ended December 31, 2020 (in MBoe):
Balance, Dec 31, 2019
Acquisition of reserves
Extensions and discoveries
Revisions of previous estimates
SEC pricing reduction
Development timing and 5-year rule
Transfer to estimated proved developed
Balance, Dec 31, 2020
Proved
Undeveloped
Reserves
15,131
389
374
882
(1,118)
(7,036)
(1,700)
6,922
Changes in PUDs that occurred during 2020 were primarily dued
to:
•
the acquisition of additional mineral and royalty interests located in the Permian, Anadarko, Williston and DJ Basins in
multiple transactions, which included 389 MBoe of additional PUD reserves;
• well additions, extensions and discoveries of approximately 374 MBoe, as 94 horizontal well locations were converted
from probable, possible and contingent resource to PUDs due to continuous activity and delineation of additional
zones on our mineral and royalty interests, offset by
•
•
•
•
negative revisions of 1,118 MBoe attributable to a reductd
ion in SEC pricing;
positive revision of 882 MBoe attributablea
processing assumptim ons, and unit configuration; and
to estimate ultimate recovery ("EUR") adjustments, refined gas and NGL
as a result of decreased operator activity throughout 2020, a reclass of 7,036 MBoe to non-proved due to future
locations falling outside the SEC 5-year ruler
for PUDs; and
the conversion of approximately 1,700 MBoe in PUD reserves into proved developed reserves as 184 horizontal
locations were drilled and/or completed.
As a mineral and royalty interests owner, we do not incur any capita
connection with the development of our PUDs, which costs are borne entirely by the operator. As a result, during
ended December 31, 2020, we did not have any expenditures
to convert PUDs to proved developed reserves.
d
t
al expenditures or lease operating expenses in
the year
We identify drilling locations based on our assessment of current geologic, engineering and land data. This includes DSU
formation and current well spacing information derived from state agencies and the operations of the exploration and
production companies drilling our mineral and royalty interests. We generally do not have evidence of approval of our
operators’ development plans, however, we use a deterministic approach to define and allocate locations to proved reserves.
While many of our locations qualify as geologic PUDs, we limit our PUDs to the quantities of oil and gas that are reasonably
certain to be recovered in the next five years. As of December 31, 2020 and 2019, approximately 28% and 46%, respectively, of
our total proved reserves were classified as PUDs.
Oil, Natural Gas and NGL Production Prices and Costs
21
Production and Price History
The following tabla e sets forth
ff
information regarding net production of oil, natural gas and NGLs, and certain price and cost
information for each of the periods indicated:
Production Data:
Oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Total (MBoe)(1)(2)
Average realized prices(3):
Oil ($/Bbl)
Natural gas ($/Mcf)
NGLs ($/Bbl)
Total ($/Boe)(2)
Average costs (per Boe);
Gathering, transportation and marketing
Severance and ad valorem taxes
Depreciation, depletion, and amortization
General and administrative(4)
Interest expense, net
Loss (gain) on derivative instruments, net
Total
Years Ended December 31,
2020
2019
2018
1,823
5,809
680
3,471
1,515
4,707
407
2,706
37.26
$
54.16
$
$
$
1.80
11.61
24.85
2.01
1.62
13.90
4.06
0.26
—
$
$
2.07
15.03
36.17
1.84
2.37
11.43
4.40
2.07
0.21
21.85
$
22.32
$
777
2,507
222
1,417
60.56
2.80
25.72
42.19
2.78
2.50
9.82
4.69
5.26
(0.30)
24.75
$
$
$
$
(1) May not sum or recalculate due to rounding.
(2) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil
equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.
(3) Excludes the effect of commodity derivative instruments.
(4) General and administrative expenses exclude share-based compensation expenses.
Productive Wells
Productive wells consist of producing horizontal wells, wells capabl
e of production and exploratory, development or
extension wells that are not dry wells. As of December 31, 2020, we owned mineral and royalty interests in 5,985 gross
productive horizontal wells, which consisted of 5,398 oil wells and 587 natural
gas wells.
a
t
We do not own any working interests in any wells. Accordingly, we do not own any net wells as such term is defined by
Item 1208(c)(2) of Regulation S-K.
Acreage
The following tablea
sets forth information relating to our acreage for our mineral and royalty interests as of December 31,
2020:
22
Basin
Delaware
Midland
SCOOP
STACK
DJ
Williston
Other
Total
Gross DSU
Acreage
Net Royalty
Acreage
100% Royalty
Acreage
345,770
123,815
208,455
179,960
174,535
503,455
146,345
1,682,335
28,330
5,220
11,400
10,725
15,890
7,950
6,770
86,285
3,540
650
1,430
1,340
1,990
990
850
10,790
The vast majority of our mineral and royalty interests are leased to our operators with greater than 90% of our
approximately 80,195 leased net royalty acres being held by production as of December 31, 2020. In addition, we had
approximately 6,090 net royalty acres that were not leased as of December 31, 2020.
Drilling Results
ff
sets forth
The following tablea
information with respect to the number of wells turned to production on our properties
during the periods indicated. The information should not be considered indicative of future perforff mance, nor should it be
assumed that there is necessarily any correlation among the number of productive wells drilled, the quantities of reserves found
and the economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they
produce a reasonable rate of return.
As a mineral and royalty interest owner, we generally are not provided information as to
whether any wells drilled on the properties underlying our acreage are classified as exploratory.
ff
t
Development wells:
Productive
Dry(1)
Total
Years Ended December 31,
2020
2019
2018
719
—
719
906
—
906
1,036
—
1,036
(1) We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.
Regulation of Environmental and Occupational Safety and Health Matters
t
Oil, natural
gas and NGL exploration, development and production operations are subject
laws and
regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or
occupational health and safety.t These laws and regulations have the potential to impact production on our properties, including
requirements to:
to stringent
•
•
•
•
•
•
obtain permits to conduct regulated activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
restrict the types, quantities and concentration of materials that can be released into the environment in the
performance of drilling and production activities;
initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as
restoration of drilling pits and plugging of abandoned wells;
a
apply
specific health and safety ct
riteria addressing worker protection; and
impose substantial liabila
ities forff
pollution resulting from operations.
Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and
criminal sanctions, including monetary penalties, the imposition of strict, joint and several liabia lity, investigatory and remedial
23
obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. Moreover,
gas and NGL production below the rate that would
these laws, rulrr es and regulations may restrict the rate of oil, natural
otherwise be possible. The regulatory burden on the oil and natural
gas industry increases the cost of doing business in the
industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and
limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-
interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management,
completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost to our
operators of developing our properties. Moreover, accidental releases or spills may occur in the course of operations on our
properties, causing our operators to incur significant costs and liabilities as a result of such releases or spills, including any
third-party claims forff
damage to property, natural resources or persons.
t
t
Increased costs or operating restrictions on our properties as a result of compliance with environmental laws could result
in reduced exploratory and production activities on our properties and, as a result, our revenues and results of operations. The
following is a summary of certain existing environmental, health and safety l
aws and regulations, each as amended from time to
time, to which operations on our properties are subject.
t
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” also known as the
Superfund law, and comparablea
state laws impose liability without regard to fault or the legality of the original conduct on
certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment.
Under CERCLA, these “responsible persons” may include the owner or operator of the site where the release occurred, and
entities that transport, dispose of or arrange for the transport or disposal of hazardous substances released at the site. These
responsible persons may be subject to joint and several strict liabia lity for the costs of cleaning up the hazardous substances that
resources and for the costs of certain health studies. CERCLA
have been released into the environment, forff
also authorizes the U.S. Environmental Protection Agency ("EPA") and, in some instances, third parties to act in response to
threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they
incur. It is not uncommon for neighboring landowners and other third-parties to filff e claims forff
personal injury and property
damage allegedly caused by the hazardous substances released into the environment.
damages to natural
t
The Resource Conservation and Recovery Act (“RCRA”)RR
state laws control the management and disposal
of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and
disposal of wastes generated. Drilling fluids, produced waters and most of the other wastes associated with the exploration,
gas and NGLs, if properly handled, are currently exempt from regulation as
development and production of oil, natural
hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state
laws or other fede
ral laws. However, it is possible that certain oil, natural gas and NGL drilling and production wastes now
classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in
the costs to manage and dispose of wastes, which could increase the costs of our operators’ operations.
and comparablea
ff
t
t
Certain of our properties have been used for oil and natural
gas exploration and production for many years. Although the
operators may have utilized operating and disposal practices that were standard in the industry at the time, petroleum
hydrocarbons and wastes may have been disposed of or released on or under our properties, or on or under other offsite
locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. Our properties and the
petroleum hydrocarbons and wastes disposed or released thereon may be subject to CERCLA, RCRA aRR
nd analogous state laws.
Under such laws, the owner or operator could be required to remove or remediate previously disposed wastes, to clean upu
contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to
prevent futuret
contamination or to pay some or all of the costs of any such action.
Water Discharges and NORM
The Federal Water Pollution Control Act, also known as the “Clean Water Act,” and analogous state laws imposm e
restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into fede
ral and state
waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued
by the EPA or an analogous state agency. The scope of federal jurisdictional reach over waters of the United States
(“WOTUS”) has been subject to substantial revision in recent years. In January 2020, the EPA and the U.S. Army Corps of
Engineers (the “Corps”) replaced a prior 2015 rule with the narrower Navigablea Waters Protection Rule; challenges are pending
against these rulemakings, and the Biden Administration may propose a diffeff
rent interpretation of WOTUS. Therefore, the
scope of jurisdiction under the Clean Water Act is uncertain at this time, and any increase in scope could result in increased
our operators. In addition, federal and state regulatory
certain activities forff
costs or delays with respect to obtaining permits forff
non-compliance with discharge permits or other
agencies can impose administrative, civil and criminal penalties forff
ff
24
requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure
plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures
to help
or leak. In addition, the Clean
prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture
discharges of storm water
Water Act and analogous state laws require individual permits or coverage under general permits forff
ilities. The Oil Pollution Act of 1990, as amended, or “OPA,” amends the Clean Water Act and
runoff from certain types of facff
establia
resource damages liability for unauthorized discharges of oil into waters of the United
States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a
worst case discharge of oil into waters of the United States.
shes strict liabia lity and natural
r
t
t
In addition, natural
ly occurring radioactive material (“NORM”) is brought to the surface in connection with oil and gas
production. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned
treatment works into surface waters), which may increase the costs associated with management of NORM.
t
Air Emissions
a
The Clean Air Act of 1963 (“CAA”) and comparablea
for the construction or modification of certain projects or facff
state laws restrict the emission of air pollutants from many sources
through air emissions permitting programs and also impose various monitoring and reporting requirements. These laws and
regulations may require our operators to obtain pre-approval
ilities
expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or
incur development expenses to install and utilize specific equipment or technologies to control emissions. For example, in
December 2019, the EPA reclassified Colorado’s ozone nonattainment areas under the National Ambient Air Quality Standards
from moderate to serious nonattainment; also, the Colorado Air Quality Control Commission has approved new rules to reduce
emissions from oil and gas operations in the state, including requirements forff more extensive emissions monitoring and
reporting. These revisions could increase the costs of development and production on our properties, potentially impairing the
gas
economic development of our properties. Obtaining permits has the potential to delay the development of oil and natural
projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties forff
non-compliance with
air permits or other requirements of the CAA and associated state laws and regulations.
t
Climate Change
The threat of climate change continues to attract considerablea
attention in the United States and in foreign countries,
numerous proposals have been made and could continue to be made at the international, national, regional, and state levels of
government to monitor and limit existing emissions of greenhouse gasses (“GHGs”) as well as to restrict or eliminate such
future emissions.
In the United States, no comprehensive climate change legislation has been implemented at the federa
l level. However,
President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive
orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a
pollutant under the CAA, the EPA has adopted regulations that, among other things, establia
sh construction and operating permit
reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG
gas system sources in the United States, and together with the U.S. Department of
emissions from certain petroleum and natural
Transportation (the “DOT”), implementing GHG emissions limits on vehicles manufactured
for operation in the United States.
t
The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. For more information, see
our regulatory disclosure titled “Hydraulic Fracturing
Activities.”
ff
t
t
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulation or other
regulatory initiatives that are focused on such areas GHG cap a
nd trade programs, carbon taxes, reporting and tracking
a
programs, and restriction of emissions. At the international level, the United Nations sponsored “Paris Agreement” requires
member states to submit non-binding, individually-determined reduction goals known
as Nationally Determined Contributions
(“NDCs”) every five years after 2020. Although the United States had withdrawn from the Paris Agreement, President Biden
has signed executive orders recommitting the United States to the agreement and calling on the federal government to develop
the United States’ NDC. However, the impacts of these executive orders and the terms of any legislation or regulation to
implm ement the United States’ commitment remain unclear at this time.
k
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted
in increasing political risks in the United States, including action taken by President Biden with respect to his climate change
related pledges. On January 27, 2021, President Biden issued an executive order that calls for substantial action on climate
change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination
of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies
25
and economic sectors. The Biden Administration has also issued orders temporarily suspending the issuance of authorizations,
and suspending the issuance of new leases pending a study, for oil and gas development on federal lands. Substantially all of
our mineral interests are located on private lands, but we cannot predict the full impact of these developments or whether the
Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may
include the imposition of more restrictive requirements for the establia
or the permitting of
liquified natural
gas (“LNG”) export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities.
Litigation risks are also increasing as a number of cities and other local governments have sought to bring suit against the
gas companies in state or federal court, alleging among other things, that such companies created public
largest oil and natural
nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse
effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those
impacts.
shment of pipeline infrastructuret
t
t
There are also increasing financial risks forff
fossil fuel producers as shareholders currently invested in fossil-fuel energy
companies concerned about the potential effects of climate change may elect in the future to shift some or all of their
investments into non-energy related sectors. Instituti
onal lenders who provide financing to fossil-fuel energy companies also
have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel
ff
of
energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect
reducing the funding provided to the fossil fuel
sector. Recently, President Biden signed an executive order calling for the
development of a “climate finff ance plan” and, separately, the Federal Reserve joined the Network for Greening the Financial
System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of
energy companies could result in the restriction, delay or cancellation of drilling
investments in and financing for fossil fuel
programs or development or production activities.
ff
ff
ff
t
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other
gas sector or otherwise
regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural
gas or generate the GHG emissions could result in increased
restrict the areas in which this sector may produce oil and natural
gas, which could reduce the
costs of compliance or costs of consuming, and thereby reduce demand for oil and natural
gas operators
profitability of our interests. Additionally, political, litigation and financial risks may result in our oil and natural
restricting or cancelling production activities, incurring liability for infrastructuret
damages as a result of climatic changes, or
impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests.
One or more of these developments could have a material adverse effect on our business, financial condition and results of
operation.
t
t
t
t
Hydraulic Fracturing Activities
A substantial portion of the production on our properties involved the use of hydraulic fracturing techniques. Hydraulic
fracturing is an important and common practice that is used to stimulate production of oil, natural
dense
subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemical additives under
pressure into the formation to fracturet
the surrounding rock and stimulate production.
gas and NGLs fromff
t
ff
Hydraulic fracff
turing typically is regulated by state oil and natural
t
ral regulatory authority pursuant to the U.S. Safe Drinking Water Act (“SDWA”) over certain hydraulic fracff
gas commissions or similar agencies, but the EPA has
asserted fede
turing
activities involving the use of diesel fuel in fracturing fluids and issued permitting guidance that applies to such activities.
Additionally, the EPA issued finaff
l CAA regulations in 2012 and in June 2016 governing performance standards, including
standards for the captur
e of emissions of methane and volatile organic compounds released during hydraulic fracturing. In
September 2020, the Trump Administration revised these regulations to remove the transmission and storage segments from the
nd rescind the methane-specific requirements applicable to sources in the production and
oil and natural gas source category arr
processing segments. However, President Biden has signed an executive order calling for the suspension, revision, or rescission
of the September 2020 rule, and the reinstatement or issuance of methane emissions standards for new, modified, and existing
oil and gas facilities.
a
Also, in December 2016, the EPA released its finff al report on the potential impacts of hydraulic fracturing on drinking
turing may impact
water resources. The final report concluded that “water cycle” activities associated with hydraulic fracff
drinking water resources “under some circumstances,” noting that the following hydraulic fracff
turing water cycle activities and
local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals
for fracturing in times or areas of low water availabila
ity; surface spills during the management of fracturing fluids, chemicals or
produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids
directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or
storage of fracturing
wastewater in unlined pits.
t
26
In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of
hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction
and temporary or permanent bans on hydraulic fracturing in certain areas. For example, Texas, Colorado and North Dakota,
impose new or more stringent permitting, disclosure, disposal and well
among others, have adopted regulations that
construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic
fracturing altogether. Separately, in Texas, there has been increased pressure on the Railroad Commission (“RRC”) to impose
more stringent limitations on the flaring of gas from oil wells to prevent waste and because of increased concerns related to the
ring. The RRC continues to approve flaring permits, but at least one lawsuit has been filff ed by a
environmental effects of flaff
pipeline operator challenging the RRC’s flar
l practices. Additionally, the RRC has approved a new flaring request
form, which may result in reducing approvals for flaring. Any future requirements limiting flaring could adversely affect
exploration and production activities on our properties and result in increased costs to connect wells to pipelines. In addition to
state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in
particular. For more information on such restrictions in Colorado, see “Item 1A—Risk Factors—Federal and state legislative
and regulatory initiatives relating to hydraulic fracturing could result in our operators incurring increased costs, additional
operating restrictions or delays and fewer potential drilling locations.” If new federal, state or local laws or regulations that
significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling
and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or
prohibiting hydraulic fracturing could result in decreased oil, natural
gas and NGL exploration and production activities and,
therefore, adversely affecff
t the development of our properties.
ing approva
a
ff
t
Endangered Species Act
The Endangered Species Act (the “ESA”) restricts activities that may affect endangered and threatened species or their
habitats. The designation of previously unidentified endangered or threatened species could cause our operators to incur
additional costs or become subject to operating delays, restrictions or bans in the affected areas. Recently, there have been
renewed calls to review protections currently in place for the Dunes Sagebrusrr h Lizard, whose habitat includes the Permian
Basin; Lesser Prairie Chicken, which can be found
in portions of the Central and Southern Great Plains; and Greater Sage
Grouse, which can be found
across a large swath of the northwestern United States in oil and gas producing states, and to
reconsider listing the species under the ESA. In July 2020, the US Fish and Wildlife Service determined that sufficient
information had been presented to warrant a 12-month review for listing of the Dunes Sagebrusrr h Lizard, which review is
ongoing; the agency is also reviewing a candidate conservation agreement with assurances forff
the species. To the extent species
are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in
areas where our properties are located, operations on those properties could incur increased costs arising from species
protection measures and facff e delays or limitations with respect to production activities thereon.
ff
ff
Employee Health and Safety
ral and state laws and regulations, including the federal
Operations on our properties are subject to a number of fede
ional Safety and Health Act, or “OSHA,” and comparablea
state statutes, whose purpose is to protect the health and
Occupatu
f workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under
safety ot
Title III of the federal Superfund
state statutes require that information be
maintained concerning hazardous materials used or produced in operations and that this information be provided to employees,
state and local government authorities and citizens.
Amendment and Reauthorization Act and comparablea
u
ff
Judicial and Legislative Matters
Muscogee (Creek) Nation Reservationtt
On July 9, 2020, the U.S. Supreme Court ruled that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not
been disestablished. Prior to the Court’s ruling, the prevailing view was that the Muscogee (Creek) Nation, Chickasaw Nation,
Cherokee Nation, Choctaw Nation and Seminole Nation reservations within Oklahoma had been disestablished prior to
statehood in 1907. Although the Court’s ruling indicates that it is limited to criminal law as applied within the Muscogee
(Creek) Nation reservation, the ruling has significant potential implications for civil law within the Muscogee (Creek) Nation
reservation, as well as other reservations in Oklahoma that may similarly be found to not have been disestablia
shed. While we
cannot predict the full extent to which civil jurisdiction may be affected, the ruling could adversely affect title to our mineral
interests, to the extent they are found to be located within reservation areas, and significantly impact laws and regulations to
which we and our operators and interests are subject in Oklahoma, such as taxation, environmental regulation, and the
permitting and siting of energy assets.
27
a
State district courts in Oklahoma, appl
ying the analysis in U.S. Supreme Court’s ruling regarding the Muscogee (Creek)
Nation, have ruled that the Cherokee, Chickasaw, Seminole and Choctaw reservations likewise have not been disestablished.
On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe,ff Accountablea
,
Flexible, Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-
approved regulatory programs to Indian County within Oklahoma except: Indian allotment to which Indian titles have not been
extinguished; lands that are held in trust by the United States on behalf of any Indian or Tribe; and lands that are owned in fee
by any Tribe where title was acquired through a treaty with the United States to which a Tribe is a party and that have never
existing EPA-approved
been allotted to any citizen or member of such Tribe. The approval extends Oklahoma’s authority forff
regulatory programs to lands within Oklahoma previously under the jurisdiction of the State before the U.S. Supreme Court’s
ruling regarding the Muscogee (Creek) Nation reservation. However, several Tribes have expressed dissatisfaction with the
consultation process performed in relation to this approva
l, and it is possible that the EPA’s approval under the SAFETE Act
could be challenged. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by
the EPA. At this time,
the EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval fromff
we cannot predict how these jurisdictional issues may ultimately be resolved. We will continue to monitor developments
concerning these matters.
a
a
Dakota Access Pipeii
lineii
(“DAPL”)
On July 6, 2020, the U.S. District Court for the District of Columbia ordered vacaturt
of DAPL’s easement from the
“Corps” and further ordered the shutdown of the pipeline by August 5, 2020 while the Corps completes a full
environmental
of
impact statement for the project. On January 26, 2021, the Court of Appeals forff
the easement, but declined to require the pipeline to shut down while an Environmental Impact Statement is prepared. However,
the Court of Appeals stated that the Corps may require the pipeline to shutdown pending the required environmental review,
and the District Court is currently considering whether to enjoin the operation of the pipeline due to the lack of an easement.
If the legal challenges to DAPL are successful, transportation costs for
The District Court has not yet ruled on this matter.
crude oil will likely increase in the Williston Basin, and the operators of our properties in the Williston Basin may choose to
shut in wells if they are unable to connect those wells to other pipelines or obtain sufficient capac
ity on other pipelines at an
effect
ive cost, both of which may adversely impact our revenues and future production from our properties in the Williston
ff
Basin.
the District of Columbia affirmed the vacaturt
a
ff
Implementation of Colorado SB 19-181 (“SB 181”)
the
In November 2020, the Colorado Oil and Gas Conservation Committee ("COGCC"), as part of SB 181’s mandate forff
COGCC to prioritize public health and environmental concerns in its decisions, adopted revisions to several regulations to
increase protections for public health, safety,t welfare, wildlife, and environmental resources. Most significantly, these revisions
ks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminate
establia
sh more stringent setbac
ct to only limited exceptions. Some
gas at new or existing wells across the state, each subjeu
t
routine flaring and venting of natural
local communities have adopted, or are considering adopting, further restrictions for oil and gas activities, such as requiring
greater setbacks. The Colorado Department of Public Health and the Environment also recently finff alized ruler
s related to the
control of emissions from certain pre-production activities. These and other developments related to the implementation of SB
181 could adversely impact our revenues and futuret
production from our properties.
t
Title to Properties
Prior to completing an acquisition of mineral and royalty interests, we performff
a title review on each tract to be acquired.
of mineral and royalty interest owned by a prospective seller, the property’s
and royalty amount as well as encumbrances or other related burdens. For our Texas properties, we obtain a limited
As a result, title examinations have been obtained on a significant
Our title review is meant to confirm the quantumt
lease statust
title memorandum rendered by an oil and gas law firm.
portion of our properties.
ff
In addition to our initial title work, operators often will conduct a thorough title examination prior to leasing and/or
drilling a well. Should an operator’s title work uncover any further title defects, either we or the operator will perforff m curative
work with respect to such defects. An operator generally will not commence drilling operations on a property until any material
title defects on such property have been cured. We believe that the title to our assets is satisfactory in all material respects.
Although title to these properties is in some cases subject to encumbrances, such as customary interests generally retained in
connection with the acquisition of oil and gas interests, non-participating royalty interests and other burdens, easements,
restrictions or minor encumbrances customary in the oil and natural
gas industry, we believe that none of these encumbrances
t
will materially detract fromff
the value of these properties or from our interest in these properties.
Competition
28
t
gas leases and personnel required to findff
gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of
The oil and natural
and produce reserves. Many of our competitors not only
minerals and oil and natural
t
own and acquire mineral and royalty interests but also explore for and produce oil and natural
gas and, in some cases, carry on
midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. By
engaging in such other activities, our competitors may be abla e to develop or obtain information that is superior to the
information that is availablea
to us. In addition, certain of our competitors may possess financial or other resources substantially
larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves in the future will be
dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive
environment.
t
In addition, oil and natural
t
price. These alternate forms
natural
ff
t
convert to alternate fueff
gas or other forms
ff
gas products compete with other forms
of energy include electricity, coal, and fuel
of energy available to customers, primarily based on
ity or price of oil and
oils. Changes in the availabila
of energy, as well as business conditions, conservation, legislation, regulations, and the ability to
ff
ff
ls and other forms of energy may affect the demand for oil and natural gas.
Seasonality of Business
t
gas produced fromff
the wells on our properties during
Weather conditions affect the demand for, and prices of, natural
gas and can also delay drilling activities, disrupting our
overall business plans. Additionally, some of the areas in which our properties are located are adversely affected by seasonal
weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, our operators may be unable
to move their equipment between locations, thereby reducing their ability to operate our wells, reducing the amount of oil and
natural
ry
t
2021 adversely affected operator activity and production volumes in the southern United States, including in the Permian Basin.
Additionally, extended drought conditions in the areas in which our properties are located could impact our operators’ ability to
the
source sufficient water or increase the cost for such water. Furthermore, demand for natural
gas production during our first and fourth quarters. Certain natural
winter, resulting in higher natural
gas prices for our natural
gas users utilize natut ral gas storage facilities and purchase some of their anticipated winter requirements during
the summer,
which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and
other oil and natural
gas operations in a portion of our operating areas. Due to these seasonal fluctuations, our results of
operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.
gas is typically higher during
t
such times. For example, the recent winter storms in Februarr
d
d
d
t
t
t
t
Culture
Human Capital Resources
ive working environment and shared sense of purpose that differenti
Our employees are one of our most valuable assets. Our small size and organizational structuret
promote a highly
collaborat
ates us from our competitors. In addition, we rely
a
on the strength of our technical expertise, particularly those individuals engaged in our engineering and geology departments, to
inform our investment decisions and portfolio construction and management. Given our team’s understanding of oil and gas
operations, we are able to better assess risk inherent in the mineral and royalty assets we acquire.
ff
Headcount and Demographics
As of December 31, 2020, we had 43 full-time employees and 9 temporary employees. All of our employees are located
in our Austin, Texas office. In addition to our two founders, we have approximately 12 full
-time employees in our engineering
and geology departments, seven full-time employees dedicated to our ground game acquisition and business development
departments, nine full-time employees in our land department, and 13 full-time employees in our finance, accounting,
information technology and legal departments. The vast majori
ty of our temporary employees are part-time employees that
assist the ground game acquisition and business development departments. Approximately 44 % of our employees are female
and approximately 33% of our employees identify as minorities. We have no collective bargaining agreements with our
employees. We believe that our employee relationships are satisfactory. We hire independent contractors on an as needed basis.
a
ff
Competitive Compensation and Benefits
Our compensation programs are designed to align the compensation of our employees with our performance and to
provide the proper incentives to attract, retain and motivate our employees to achieve top-quality results. Specifically:
• We engage a nationally recognized outside compensation and benefits consulting firm to provide benchmarking
against our peers within the industry forff
executive compensation.
29
• Our executive compensation program is designed to attract, motivate and retain high-quality leadership and incentivize
our executive officers to achieve performance goals over the short- and long-term, which also aligns the interests of
our executive officers with those of our stockholders. As such, our compensation program for our executive officers is
heavily weighted toward equity-based compensation and does not include an annual cash bonus. Equity-based
compensation generally includes both restricted stock units subject to time-based vesting and restricted stock units
subject to performance-based vesting.
• All full-time employees are eligible for health insurance paid forff
100% by us, paid and unpaid leaves, including
parental leave, a retirement plan and disabila
ity/accident coverage.
• We have a corporate philanthropy program that provides matching gifts by us forff
both monetary gifts by employees
and time volunteered by employees during their personal time, along with group opportunities for employees to
volunteer together once a quarter during
company time.
d
• We have an education reimbursement program to assist our employees in developing knowledge, skills and job
effectiveness through higher education.
Training and Development
In light of our small size and collaborat
l
ive working environment, we currently do not have a need to implement a forma
in-house training and development program. Instead, we emphasize on-the-job training, informal mentoring and encourage our
employees to participate in external training and development courses, programs and professional organizations. Our employees
are encouraged to take responsibility forff
their development, and we are committed to ensuring that they have the resources they
need to succeed.
a
ff
Retention and Tenure
The combination of our culture, competitive compensation, career growth and development opportunities foster employee
tenure and reduce voluntary turnover rates. The average tenure of our employees is approxim
a
ff
ately four
years.
Workplace Safety
We care about the safety of our colleagues and all visitors to our workplace. During 2020, our focus on workplace safetyt
enablea
d us to preserve business continuity during the COVID-19 pandemic, reopen our offices in a safe manner in May 2020
and remain open. Prior to our reopening, our building management enhanced the HVAC filtration system throughout the
-time employees into individual
building. We provided additional enhancements to our office space, including moving all full
offices to increase physical distancing and installing a plasma air system, hand sanitizing stations and safety s
ignage. Further,
we implemented a variety of office protocols for our employees to follow when in our office space. These include, but are not
limited to, daily self-monitoring for COVID-19 symptoms, written affirmations that employees are symptom free prior to
coming to the office and masking requirements.
ff
t
30
Item 1A. Risk Factors
Summary of Risk Factors
An investment in our shares of Class A common stock involves a significant degree of risk. Below is a summary of certain
risk factors that you should consider in evaluating us and our Class A common stock. However, this list is not exhaustive.
Before you invest in our Class A common stock, you should carefully consider the risk facto
rs discussed or referenced below
and under Item 1A. “Risk Factors” in this Annual Report on Form 10-K. If any of the risks discussed below and under Item 1A.
“Risk Factors” were actually to occur, our business, financial condition, results of operations and cash flows could be adversely
affected and our results could differ materially fromff
expected and historical results, and of which may also adversely affect the
holders of our Class A common stock.
ff
Risks Related to Our Business
• The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material
adverse effecff
ts on our business, financial position, results of operations and/or cash flows.
• Substantially all of our revenues are derived from royalty payments that are based on the price at which oil, natural
t
gas
and NGLs produced from the acreage underlying our interests is sold.
• We depend on various unaffiliated operators for all of the exploration, development and production on the properties
underlying our mineral and royalty interests.
• Our failure to successfully identify, complete and integrate acquisitions could adversely affect our growth and results
of operations.
• Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.
• Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the
occurrence or timing of their drilling.
• We may experience delays in the payment of royalties and be unable to replace operators that do not make required
lting lessees if any of the operators on
royalty payments, and we may not be able to terminate our leases with defauff
those leases declare bankruptcy. We may also experience improper deductions in the payment of royalties.
• Acquisitions and our operators’ development activities of our leases will require substantial capital, and we and our
to obtain needed capia tal or finff ancing on satisfactory terms or at all.
operators may be unablea
• Our future success depends on replacing reserves through acquisitions and the exploration and development activities
of the operators of our properties.
• We have little to no control over the timing of futuret
drilling with respect to our mineral and royalty interests.
• Project areas on our properties, which are in various stages of development, may not yield oil, natural
t
gas or NGLs in
commercially viable quantities.
• The unavailability, high cost or shortages of rigs, equipment, raw materials, suppli
in increased costs for operators related to developing and operating our properties.
u
es or personnel may restrict or result
• The marketability of oil, natural
t
gas and NGL production is dependent upon transportation, pipelines and refining
facilities, which neither we nor many of our operators’ control.
• Our estimated reserves are based on many assumptim ons that may turnt
out to be inaccurate.
•
t
If oil, natural
prices in 2020, we could be required to record additional impairments of our proved oil, natural
properties that would constitute a charge to earnings and reduce our shareholders’ equity.
gas and NGL prices decline significantly, such as in the case of the significant decline in commodity
gas and NGL
t
Risks Related to Environmental and Regulatory Matters
• Conservation measures, technological advances, general concern about the environmental impact of the production and
use of fossil fuels and increasing attention to environmental, social and governance (“ESG”) matters could materially
31
reduce demand for oil, natural
the trading market forff
t
shares of our Class A common stock.
gas and NGLs and adversely affect our results of operations, availability of capita
al and
• Oil, natural
t
gas and NGL operations are subject to various governmental laws and regulations. Compliance with these
laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our
operators incurring significant liabilities, either of which may impact our operators’ willingness to develop our
interests.
• Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in our operators
incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.
Risks Related to Our Financial and Debt Arrangements
• Our derivative activities could result in financial losses and reduce earnings.
• Our revolving credit facff
ility has substantial restrictions and finaff
ncial covenants that may restrict our business and
financing activities and our ability to declare dividends.
Risks Related to Our Class A Common Stock
• Brigham Minerals is a holding company. Brigham Minerals’ sole material asset is its equity interest in Brigham LLC
and it is accordingly dependent upon distributions from Brigham LLC to pay taxes, cover its corporate and other
overhead expenses and pay any dividends on our Class A common stock.
• The requirements of being a public company, including compliance with the reporting requirements of the Securities
Exchange Act of 1934, as amended (the “Exchange Act”) and the requirements of the Sarbanes-Oxley Act of 2002 (the
“Sarbanes-Oxley Act”), may strain our resources, increase our costs and distract management, and we may be unable
to comply with these requirements in a timely or cost-effective manner.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our
financial results or prevent fraud.
•
• Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with
us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time
or pursuing business opportunit
ies.
t
• Our Sponsors and their affiliates are not limited in their ability to compete with us, and the corporate opportunity
our Sponsors to benefit from
provisions in our amended and restated certificate of incorporation could enablea
corporate opportunities that might otherwise be availablea
to us.
Risk Factors
The following are certain risk factors that affecff
i
t
on with r
These risk fact
Many of these risks are beyond our control.
own investigati
tt
risk factors in addition to the other informr ation included in this Aii
Statement Regarding
financial condition, results of operations and cash flows could bll
from expex
Forward-Looking Statements.”tt
cted and histori
e
ii
cal results, any of which may also adversely affecff
ors are not exhaustive and investors arr
t our business, financial condition, results of operations and cash flows.
ir
ff
following
y cll
including matters addressed under “Cautionary
ccur, our business,
ted, and our results could diffeff r materially
If any of the events described below were to actually oll
re encouraged to perform t
nnual Report,
onsider thett
hett
e
rr
ff
espect to our business, financial condition and prospects.tt You should carefull
e adversely affecff
ll
holders
t thett
of our Class A common stock.kk
Risks Related to Our Business
The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material
adverse effects on our business, financial position, results of operations and/or cash flows.
We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control,
and could significantly disrupt our operations and adversely affect our financial condition. For example, the continuing global
spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, has caused a disrupti
on to the oil and natural
gas industry and to our business. The COVID-19 pandemic has negatively impacted the global economy, disrupted global
supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and
commodity markets. Furthermore, the COVID-19 pandemic has affected our operations by (i) rendering our personnel unable to
an extended period of time, (ii) contributing to a steep decline in commodities prices in 2020,
access company facilities forff
r
t
32
al markets on terms favorablea
which has reduced activity by our operators and the amounts of royalty payments we receive, (iii) causing some of the
Company’s operators to shut in and curtail production from wells on the Company’s properties forff
a period of time, (iv)
limiting our access to the capita
al resources and (v) reducing
to identify, limiting our ability to execute on our growth
the level of potential acquisition opportunities we have been ablea
strategy of acquiring additional mineral and royalty interests. Additionally, the steps taken by national, state and local
governments to curb the spread of the COVID-19 pandemic, including stay-at-home orders, quarantines, travel restrictions and
business shutdowns, and the implications on our operators’ workforce of a COVID-19 infection, have limited our operators’
ability to maintain production from our properties. Such orders and the other impacts of the COVID-19 pandemic may have
limited the ability of our operators to access our properties and maintain their existing production and development activities,
and any similar or more restrictive measures taken in the futuret
to us and adversely affected our capita
could have similar effecff
ts.
t
While our business and operations have experienced certain effects of the COVID-19 pandemic as described above, the
full extent of the impact of the COVID-19 pandemic on our operational and financial perforff mance, including our ability to
execute our business strategies and initiatives in the expected time framff
e, is uncertain and depends on various factors, including
gas (including the impact that reductions in travel, manufacturing and consumer product demand
the demand forff
oil and natural
have had and will have on the demand forff
ity of personnel, equipment and services critical to
operating production activities by our operators and the impact of potential governmental restrictions on travel, transportation
and operations. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our
operations, financial results and dividend policy will also depend on future developments, which are highly uncertain and
cannot be predicted. These developments include, but are not limited to, the duration and spread of the pandemic, its severity,
the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to
what extent normal economic and operating conditions can resume. For example, there has been a recent significant increase in
cases of COVID-19 in the U.S. that could lead to re-implementation of certain governmental restrictions. Therefore, while we
expect this matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be
reasonably estimated at this time.
commodities), the availabila
Substantially all of our revenues are derived from royalty payments that are based on the price at which oil, natural gas
and NGLs produced from the acreage underlying our interests are sold. Prices of oil, natural gas and NGLs are volatile
due to factors beyond our control. The significant drop in the price of oil in 2020 has adversely affected, and any further
decline in commodity prices in the future may adversely affect our business, financial condition or results of operations.
u
Our revenues, operating results, free cash floff w and the carrying value of our mineral and royalty interests depend
significantly upon
our properties and the prevailing prices at which
gas and NGL prices have been volatile and are subject to fluctuations in
such production is sold. Historically, oil, natural
response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control,
including:
the quantities of oil, natural
t
gas and NGLs produced fromff
t
•
the domestic and foreign supply of and demand for oil, natural
t
gas and NGLs;
• market expectations about future prices of oil, natural
t
gas and NGLs;
•
•
•
•
•
•
•
•
•
the level of global oil, natural
t
gas and NGL exploration and production;
the cost of exploring for, developing, producing and delivering oil, natural gas and NGLs;
the price and quantity of foreign imports and U.S. exports of oil, natural
t
gas and NGLs;
the level of U.S. domestic production;
the availabila
ity of storage for hydrocarbons;
political and economic conditions in the U.S. and other oil producing regions, including the Middle East, Africff
America and Russia;
a, South
the ability of members of OPEC and other countries that produce oil, naturat
oil price and production controls;
l gas, and NGLs to agree to and maintain
trading in oil, natural gas and NGL derivative contracts;
the level of consumer product demand;
33
• weather conditions and natural
t
disasters;
•
•
•
•
•
•
•
technological advances affecting energy consumption, energy storage and energy supply;
domestic and foreign governmental regulations and taxes;
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the
Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports fromff
Iran;
global or national health concerns, including health epidemics such as the ongoing COVID-19 pandemic;
the proximity, cost, availabila
ity and capaa
city of oil, natural gas and NGL pipelines and other transportation facilities;
the price and availabila
ity of alternative fuels; and
overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and
NGL price movements with any certainty. For example, during the past fivff e years, the posted price forff WTI light sweet crude
oil has ranged from a historic, record low price of negative ($36.98) per barrel in April 2020 to a high of $77.41 per barrel
in June 2018. The Henry Hrr
gas has ranged from a low of $1.33 per MMBtu in September
2020 to a high of $6.24 per MMBtu in January 2018. Certain actions by OPEC+ in the first half of 2020, combined with the
impact of the continued outbreak of the COVID-19 pandemic and a shortage in available storage for hydrocarbons in the U.S.,
contributed to the historic low price forff
oil in April 2020. While the prices for oil have begun to stabilize and also increase, such
prices have historically remained volatile, which has adversely affected the prices at which production from our properties is
sold as well as the production activities of operators on our properties and may continue to do so in the future. This, in turn, has
and will materially affecff
t the amount of royalty payments that we receive from such operators.
ub spot market price forff
t
natural
Any further decline in the price of oil, natural
t
gas and NGLs or a prolonged period of low commodity prices will also
materially adversely affecff
t our business, financial condition, results of operations and free cash flow.
t
gas and NGLs produced fromff
In addition, the quantities of oil, natural
our properties has a significant impact on our
operating results and financial condition. Lower oil, natural
gas and
NGLs that can be produced economically by our operators, which may reduce our operators’ willingness to develop and/or
to the decrease in prices for oil in 2020, many operators on our
continue to produce our properties. For example, partially dued
properties have substantially reduced their development activities in 2021 and have announced similarly reduced capita
al
expenditures
for 2021 and beyond. Additionally, lower commodity prices resulted in some of the Company's operators
temporarily shutting in or curtailing production from wells on its properties during the second quarter of 2020.
gas and NGL prices may reduce the amount of oil, natural
t
t
t
The deterioration in commodity prices, decrease in production levels, or further reduction in operator production activities
may result in our having to make substantial downward adjustments to our estimated proved, probable or possible reserves. For
example, we reclassified some of our PUD volumes to probable and possible reserves due to decreased rig activity by our
December 31, 2019 to December 31, 2020. If this
operators, resulting in a reduction of 7,036 MBoe to PUD reserves fromff
cost method of accounting
occurs or if production estimates change or exploration or development results deteriorate, the full
principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural
gas
properties. In addition, the borrowing base under our revolving credit facility is determined based on our estimated proved
reserves, and any negative revisions to our estimated proved reserves would in turn reduce our borrowing base, reducing the
amount availablea
to fund our operations through borrowings under our revolving credit facility.
ff
t
We depend on various unaffiliated operators forff
all of the exploration, development and production on the properties
underlying our mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by
these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the
failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on
our results of operations. In particular, partly in response to the significaff
oil in 2020, many of
our operators substantially reduced their development activities in 2020 and have announced similarly reduced capital
expenditures for 2021 and beyond. The number of new wells drilled in many of our focus areas has decreased, and such
slower development pace may continue in the future.
nt decrease in prices forff
Our assets consist of mineral and royalty interests. Because we depend on third-party operators for all of the exploration,
development and production on our properties, we have little to no control over the operations related to our properties. For the
ately 64% of our royalty revenues
year ended December 31, 2020, we received revenues from over 160 operators with approxim
a
34
coming fromff
the top ten operators on our properties, four of which each accounted for more than 10% of such royalty revenues.
The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our
best interests could reduce production and revenues. Furthermore, in response to the significant decrease in prices for oil in
2020, many of our operators substantially reduced their development activities in 2020 and have announced substantial
reductions in their estimated capital expenditures, rig count and completion crews for 2021 and beyond. Additionally, certain
investors have requested operators adopt initiatives to returnt
al available
capita
to our operators for investment in exploration, development and production activities. Our operators may furthe
r reduce capital
devoted to exploration, development and production on our properties in the future, which could negatively impact
expenditures
revenues we receive. The number of new wells drilled in many of our focus areas has decreased, and such slower development
pace may continue in the future, especially as a consequence of the reductions in operators’ capita
al expenditures. Moreover,
over the last year, many of our operators have announced that they plan to drill fewer
wells per section than previously
anticipated, due in part to greater well-interference between parent and child wells than previously anticipated and an increased
focus on overall capita
al efficiency in a low commodity price environment.
al to investors, which could also reduce the capita
ff
ff
t
If production on our mineral and royalty interests decreases due to decreased development activities, as a result of the low
commodity price environment, limited availability of development capita
al, production-related difficulties or otherwise, our
our
results of operations may be adversely affected. For example, the amount of royalty payments we have received fromff
operators has decreased due to the lower prices at which our operators are able to sell production from our properties and
reduced production activities by our operators. Further, depressed commodity prices caused some of our operators to
voluntarily shut in and curtail production from wells on our properties earlier in 2020. Although most of these have come back
online, an additional or extended period of depressed commodity prices may cause additional operators to take similar action or
even to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period
under more favorable pricing conditions, both of which would decrease the amount of royalty payments we receive from our
operators. Our operators are often not obligated to undertake any development activities other than those required to maintain
obligation, any development and production activities will
t
their leases on our acreage. In the absence of a specific contractual
be subject to their reasonable discretion (subject to certain implied obligations to develop imposed by the laws of some states).
Our operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and
timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on
our acreage, depends on a number of factors that are largely outside of our control, including:
•
•
•
•
•
•
•
•
•
•
•
the capia tal costs required forff
drilling activities by our operators, which could be significantly more than anticipated;
the ability of our operators to access capia tal;
prevailing commodity prices;
the operators' expected returnt
areas;
on investment in wells drilled on our acreage as comparem
d to opportunit
t
ies in other
the availabila
personnel;
ity of suitablea
drilling equipment, production and transportation infrastructuret
and qualified operating
the availabila
ity of storage for hydrocarbons;
the operators’ expertise, operating efficff
iency and finaff
ncial resources;
a
approval
of other participants in drilling wells;
the selection of technology;
the selection of counterparties for the marketing and sale of production; and
the rate of production of the reserves.
The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated
fashion, which may result in significant fluctuations in our results of operations and free cash floff w. Sustained reductions in
production by the operators on our properties may also adversely affect our results of operations and free cash floff w.
Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or
continue its operations, which could have a material adverse impact on our cash flows.
35
lure to successfulff
Our faiff
operations.
ly identify, complete and integrate acquisitions could adversely affect our growth and results of
We depend partly on acquisitions to grow our reserves, production and free cash flow. Our decision to acquire a property
will depend in part on the evaluation of data obtained fromff
production reports and engineering studies, geophysical and
geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various
interpretations. The successful acquisition of properties requires an assessment of several facff
tors, including:
•
•
•
•
•
recoverablea
reserves;
ff
future
t
oil, natural
gas and NGL prices and their appl
a
icable differe
ff
ntials;
development plans;
the operating costs our operators would incur to develop and operate the properties; and
potential environmental and other liabia lities that operators of the properties may incur.
The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition
a review of the subject properties that we believe to be
of our interests. Our review will not reveal all existing or potential
iliar with the properties to assess fully their deficiencies and
lities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so
opportunities. In connection with these assessments, we performff
generally consistent with industry practices, given the naturet
problems nor will it permit us to become sufficiently famff
capabi
a
on commercially acceptable terms.
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the
cost of, or cause us to refrain from, completing acquisitions. Additionally, acquisition opportunities vary over time. For
example, in connection with the COVID-19 pandemic and resulting market and commodity price challenges, we saw reduced
levels of potential acquisition opportunities, which constrained our ability to complete acquisitions. Our ability to complete
acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing. In addition, these
acquisitions may be in geographic regions in which we do not currently hold properties, which could subject us to additional
and unfamiliar legal and regulatory requirements. Further, the success of any completed acquisition will depend on our ability
to integrate effectively the acquired assets into our existing operations. The process of integrating acquired assets may involve
unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.
No assurance can be given that we will be able to identify suitablea
acquisition opportunities, negotiate acceptable terms,
obtain financing for acquisitions on acceptablea
terms or successfully acquire identified targets. Our failure to achieve
consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize
ties could have a material adverse effect on our financial condition, results of operations and
any unforeseen operational difficul
free cash flow. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent
acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and free cash flow.
ff
Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.
Even if we do make acquisitions that we believe will increase our cash generated fromff
operations, any acquisition
involves potential risks, including, among other things:
•
•
•
•
the validity of our assumptim ons about estimated proved, probable and possible reserves, futuret
revenues, capita
the operating expenses and costs our operators would incur to develop the minerals;
production, prices,
al expenditures,
t
a decrease in our liquidity by using a significant portion of our cash generated fromff
to finance acquisitions;
operations or borrowing capac
a
ity
a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
the assumption of unknown liabila
receive is inadequate;
ities, losses or costs forff which we are not indemnified or forff which any indemnity we
• mistaken assumptions about the overall cost of equity or debt;
•
our ability to obtain satisfacff
tory title to the assets we acquire;
36
•
•
an inabila
ity to hire, train or retain qualified personnel to manage and operate our growing business and assets; and
the occurrence of other significant changes, such as impairment of oil and natural
intangible assets, asset devaluation or restructuring
charges.
t
t
gas properties, goodwill or other
Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the
occurrence or timing of their drilling.
t
gas and NGL prices, costs, drilling results and the availabila
ity of capital, construction of and limitations on access to infrastructure,
The ability of our operators to drill and develop identified potential drilling locations depends on a number of
inclement weather,
uncertainties, including the availabila
regulatory changes and approvals, oil, natural
ity of water. Further,
our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to
drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields
gas or NGLs will be
in the same area will not enablea
present or, if present, whether oil, natural
. Even if
t
sufficient amounts of oil or natural
gas exist, our operators may damage the potentially productive hydrocarbon-bearing
formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in
production from the well or abandonment of the well. If our operators drill additional wells that they identify as dry holes in
current and future
drilling locations, their drilling success rate may decline and materially harm their business as well as ours.
gas or NGLs will be present in sufficient quantities to be economically viablea
our operators to know conclusively prior to drilling whether oil, natural
ff
t
t
t
We cannot assure you that the analogies our operators draw from available data fromff
a
the wells on our acreage, more fully
explored locations or producing fields will be appl
icable to their drilling locations. Further, initial production rates reported by
our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production
rates. Additionally, actual production from wells may be less than expected. For example, a number of operators have recently
announced that newer wells drilled close in proximity to already producing wells have produced less oil and gas than forecast.
Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be
these or any other potential drilling locations.
drilled or if our operators will be abla e to produce oil, natural gas or NGLs fromff
As such, the actual drilling activities of our operators may materially differff
from those presently identified, which could
adversely affecff
t our business, results of operation and free cash flow.
Finally, the potential drilling locations we have identified are based on the geologic and other data available to us and our
conclusions about the potential drilling
interpretation of such data. As a result, our operators may have reached different
locations on our properties, and our operators control the ultimate decision as to where and when a well is drilled.
ff
We may experience delays in the payment of royalties and be unable to replace operators that do not make required
royalty payments, and we may not be able to terminate our leases with defaultin
g lessees if any of the operators on those
leases declare bankruptcy. We may also experience improper deductions in the payment of royalties.
ff
A faiff
lure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the
property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a
replacement operator. However, we might not be able to findff
a replacement operator and, if we did, we might not be able to
enter into a new lease on favorablea
terms within a reasonable period of time. In addition, the outgoing operator could be subject
to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or
terminate the lease forff
any defaults, including non-payment, may be substantially delayed or otherwise impaired. For example,
certain of our operators have recently commenced bankruptcy proceedings under the Bankruptcy Code and their future
operations and ability to make royalty payments to us may be adversely affected by such proceedings. In general, in a
proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to
ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to
another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially
delayed, and our ultimate recovery may be only a fracff
tion of the amount owed or nothing. In addition, if we are able to enter
into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell oil or
natural
gas at the same price as the operator it replaced. Additionally, in the current low commodity price environment, some
t
operators have attempted to make improper deductions by netting negative gas price realizations against positive oil royalties
and other operators may attempt to do so in the future. We have taken action and will continue to take action to protect our
rights; however, we cannot predict whether we will ultimately be successful.
Acquisitions and our operators’ development activities of our leases will require substantial capital, and we and our
operators may be unable to obtain needed capital or financing on satisfactory terms or at all.
37
t
The oil and natural
t
gas industry is capita
in connection with the acquisition of mineral and royalty interests. To date, we have financed capita
al intensive. We make and expect to continue to make substantial capital
al expenditures
al contributions, cash generated by operations, proceeds from our IPO and from the December
expenditures
primarily with funding from capita
2019 Offering and borrowings under our debt arrangements.
In the future, we may need capital in excess of the amounts we retain in our business or borrow under our revolving credit
facility. The level of borrowing base available under our revolving credit facility is largely based on our estimated proved
reserves and our lenders' price decks and will be reduced to the extent commodity prices decrease or remain depressed.
Accordingly, our ability to access capita
al under our revolving credit facility has been adversely affected by the significant
decrease in commodity prices in 2020. Furthermore, we cannot assure you that we will be able to access other external capital
on terms favorable to us or at all. For example, given the recent significant decline in prices for oil and the broader economic
al markets on terms favorable to us may be adversely impacted. Additionally,
turmoil, our ability to secure financing in the capita
ons and institutional
al markets could be adversely affected if financial instituti
our ability to secure financing or access the capita
energy companies in connection with the adoption of sustainable lending
lenders elect not to provide funding for fossil fuel
ff
initiatives or are required to adopt policies that have the effect
sector. If we
of reducing the funding available to the fossil fuel
are unable to fund
al requirements, we may be unable to complete acquisitions, take advantage of business
opportunities or respond to competitive pressures, any of which could have a material adverse effect on our results of operation
and free cash flow.
our capita
ff
ff
ff
t
Most of our operators are also dependent on the availabila
ity of external debt and equity financing sources to maintain their
terms or at all, then we expect the
drilling programs. If those financing sources are not available to the operators on favorablea
development of our properties to be adversely affected. If the development of our properties is adversely affected, then revenues
from our mineral and royalty interests may decline.
Our future success depends on replacing reserves through acquisitions and the exploration and development activities of
the operators of our properties. Unless we replace the oil, natural gas and NGLs produced from our properties, our
results of operations and financial position could be adversely affected.
Producing oil and natural
gas wells are characterized by declining production rates that vary depending upon reservoir
t
tors. Our future oil, natural gas and NGL reserves and our operators’ production thereof and our
characteristics and other facff
free cash floff w are highly dependent on the successful development and exploitation of our current reserves and our ability to
successfully acquire additional reserves that are economically recoverablea
. Moreover, the production decline rates of our
properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We
acquire or develop additional reserves to replace the currr ent and future production of our
may also not be able to find,
acquisitions, we have little to no control over the exploration and
properties at economically acceptablea
development of our properties. If we are not able to replace or grow our oil, natural
gas and NGL reserves, our business,
financial condition and results of operations would be adversely affecff
terms. Aside fromff
ted.
ff
t
We have little to no control over the timing of future drilling with respect to our mineral and royalty interests.
As of December 31, 2020, only 18,141 MBoe of our total estimated reserves were proved developed reserves. The
remaining 6,922 MBoe, 43,759 MBoe and 22,271 MBoe of our total estimated reserves as of December 31, 2020 were PUDs,
probable undeveloped reserves and possible undeveloped reserves, respectively, and may not ultimately be developed or
produced by the operators of our properties. Recovery of undeveloped reserves requires significant capita
al expenditures and
successful drilling operations, and the decision to pursue development of an undeveloped drilling location will be made by the
operator and not by us. We generally do not have access to the estimated costs of development of these reserves or the
scheduled development plans of our operators. The reserve data included in the reserve report audited by CG&A assumes that
our operators must incur substantial capital expenditures to develop the reserves. We cannot be certain that the estimated costs
of the development of these reserves are accurate, that development will occur as scheduled
d or that the results of the
development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves
or decreases in commodity prices will reduce the future net revenues of our estimated undeveloped reserves and may result in
some projects becoming uneconomical. For example, we reclassifiedff
some of our PUD volumes to probable and possible
to decreased rig activity by our operators, resulting in a reduction of 7,036 MBoe to PUD reserves fromff
reserves dued
December 31, 2019 to December 31, 2020.
us to reclassify
certain of our proved undeveloped reserves as unproved reserves.
In addition, delays in the development of reserves could force
ff
Project areas on our properties, which are in various stages of development, may not yield oil, natural gas or NGLs in
commercially viable quantities.
38
Project areas on our properties are in various stages of development, ranging from project areas with current drilling or
production activity to project areas that have limited drilling or production history. If the wells in the process of being
completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and free
cash flow may be adversely affecff
ted.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result
in increased costs for operators related to developing and operating our properties.
t
The oil and natural
gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials
(particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times
of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases
in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be.
In accordance with customary industry practice, our operators rely on independent third-party service providers to provide
many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of
drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling rigs,
equipment, raw materials, supplies, personnel, trucking services, tubulars, hydraulic fracturing and completion services and
production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a
material adverse effecff
t on our financial condition, results of operations and freeff
cash flow.
The marketability of oil, natural gas and NGL production is dependent upon transportation, pipelines and refining
facilities, which neither we nor many of our operators' control. Any limitation in the availability of those facilities could
interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.
a
ity, proximity and capac
The marketability of our or our operators’ production depends in part on the availabila
ity of
pipelines, tanker trucks and other transportation methods, and processing and refining facilities owned by third parties. The
amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptiu
ons due
to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems,
tanker truck availability and extreme weather conditions. Also, production from our wells may be insufficient to support the
construction of pipeline facilities, and the shipment of our or our operators’ oil, natural
gas and NGLs on third-party pipelines
may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from
these and similar circumstances may last fromff
days to several months. In many cases, we or our operators are provided
only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in
gathering system or transportation, processing or refining-facility capac
ity could reduce our or our operators’ ability to market
the production from our properties and have a material adverse effect on our financial condition, results of operations and free
cash flow. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affect
ed
by federal and state regulation-including regulation of oil, natural
gas and NGL production, transportation and pipeline safety-t
t
as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our
ral, state, tribal and local laws that could adversely affect
operators rely forff
the cost, manner or feaff
transportation services are subject to complex fede
sibility of conducting our business.
a fewff
a
ff
ff
t
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies
in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our
reserves.
t
t
Oil, natural
gas and NGL reserve engineering is not an exact science and requires subjective estimates of underground
accumulations of oil, natural
gas and NGLs and assumptim ons concerning future oil, natural gas and NGL prices, production
levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved, probable and
possible reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our
estimates of proved, probable and possible reserves and related valuations as of December 31, 2020, 2019 and 2018 were
audited by CG&A. CG&A conducted a detailed review of all of our properties forff
the period covered by its reserve report using
information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of
actual drilling, testing and production. For example, due to the deterioration in commodity prices and operator activity in 2020
as a result of the COVID-19 pandemic and other facff
tors, the commodity price assumptim ons used to calculate our reserves
estimates declined, which in turn lowered our proved reserve estimates. A substantial portion of our reserve estimates are made
without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history.
Any significant variance fromff
s could greatly affect our estimates of reserves and future cash
generated from operations. Numerous changes over time to the assumptim ons on which our reserve estimates are based, as
described above, often result in the actual quantities of oil, natural
gas and NGLs that are ultimately recovered being different
t
from our reserve estimates.
these assumptim ons to actual figure
ff
39
Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current
market value of our estimated reserves. In accordance with ruler
s established by the SEC and the Financial Accounting
Standards Board, we base the estimated discounted future
net cash flows from our proved reserves on the trailing twelve-month
each
average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price forff
month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties.
Actual future
r materially from those used in the present value estimate, and future net present value
ff
estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount
factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on
interest rates in effecff
time to time and risks associated with us or the oil and natural gas industry in general.
prices and costs may diffeff
t fromff
r
ff
SEC rules could limit our ability to book additional proved undeveloped reserves in the future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to
wells scheduled to be drilled within fiveff
years after the date of booking. This requirement has limited and may continue to limit
our ability to book additional proved undeveloped reserves as the operators of our properties pursue their drilling programs.
Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required
e. Furthermore, we typically do not have access to the drilling schedules of our operators and make our
five-year timeframff
determinations about their estimated drilling schedules from any development provisions in the relevant lease agreement and
the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public
statements of our operators. Although we believe that our approach in making such determinations is conservative, the accuracy
of any such determination is inherently uncertain and subject to a number of assumptim ons and factors outside of our control,
including but not limited to those described under “We depend on various unaffiliated operators for all of the exploration,
development and production on the properties underlying our mineral and royalty interests. Substantially all of our revenue is
derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our
acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could
have an adverse effect on our results of operations. In particular, partly in response to the significant decrease in prices for oil in
2020, many of our operators substantially reduced their development activities in 2020 and have announced similarly reduced
capita
2021 and beyond. The number of new wells drilled in many of our focus areas has decreased, and such
slower development pace may continue in the future.” Any significant variance between our estimates and the actual drilling
schedules of our operators may require us to write down our proved undeveloped reserves. For example, we reclassified some
of our PUD volumes to probable and possible reserves due to decreased rig activity by our operators, resulting in a reduction of
7,036 MBoe to PUD reserves from December 31, 2019 to December 31, 2020.
al expenditures forff
nt decline in commodity prices
If oil, natural gas and NGL prices decline significaff
in 2020, we could be required to record additional impairments of our proved oil, natural gas and NGL properties that
would constitute a charge to earnings and reduce our shareholders’ equity.
ntly, such as in the case of the significaff
t
ff
gas and NGL properties forff
Accounting rules require that we review the carrying value of our oil, natural
possible
impairment at the end of each quarter. Based on specific market factors and circumstances at the time of prospective
tors, we
impairment reviews, and the continuing evaluation of development activities, production data, economics and other facff
may be required to write down the carrying value of our properties. The net capita
gas and
alized costs of our proved oil, natural
cost ceiling limitation forff which the costs are not allowed to exceed their related estimated
NGL properties are subject to a full
alized costs of evaluated properties, net of accumulated depreciation,
future net revenues discounted at 10%. To the extent capita
depletion, amortization and impairment, exceed estimated discounted future net revenues of our proved oil, natural
gas and
alized costs are charged to expense. Impairments would occur if we were to experience sufficient
NGL reserves, the excess capita
net revenues. The risk that we
downward adjustments to our estimated proved reserves or the present value of estimated future
will be required to recognize impairments of our oil, natural
gas and NGL properties increases during periods of low
commodity prices, such as those experienced in 2020. For example, we recorded a $79.6 million impairment of our oil and gas
properties, net, forff
the year ended December 31, 2020. Please see “Note 3—Oil and Gas Properties” to the consolidated and
ncial statements of Brigham Minerals included elsewhere in this Annual Report. An impairment recognized in
combined finaff
one period may not be reversed in a subsequent period even if higher oil, natural
gas and NGL prices increase the cost center
ceiling applicable to the subsequent period. If we incur impairment charges in the future, our results of operations for the
periods in which such charges are taken may be materially and adversely affecff
ted.
ff
t
t
t
t
The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion
techniques and drilling results may not meet our expectations for reserves or production.
Our operators use the latest drilling and completion techniques in their operations, and these techniques come with
inherent risks. When drilling horizontal wells, operators risk not landing the well bore in the desired drilling zone and straying
casing
from the desired drilling zone. When drilling horizontally through a forma
tion, operators risk being unable to runr
ff
40
tools and other equipment consistently through the horizontal
through the entire length of the well bore and being unable to runrr
well bore. Risks that our operators face while completing wells include being unable to fracff
ture stimulate the planned number
of stages, to run tools the entire length of the well bore during completion operations and to clean out the well bore after
completion of the final fraff cture stimulation stage. In addition, to the extent our operators engage in horizontal drilling, those
activities may adversely affect their abia lity to successfully drill in identified vertical drilling locations. Furthermore, certain of
the new techniques that our operators may adopt, such as infill drilling and multi-well pad drilling, may cause irregularities or
interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad
drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new
or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer
history of establia
shed production. Newer or emerging formations and areas often have limited or no production history and
consequently our operators will be less able to predict futff uret
drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are
drilled and production profiles are establia
shed over a sufficiently long time period. If our operators’ drilling results are weaker
than anticipated or they are unable to execute their drilling program on our properties, our operating and financial results in
these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-
gas properties and the value of our undeveloped acreage could decline, and our results of
t
downs of our oil and natural
operations and free cash flow could be adversely affecff
ted.
Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by
production. Our operators’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective
drilling opportunities. In addition, our ORRIs may be lost if the underlying acreage is not drilled before the expiration
of the applicable lease or if the lease otherwise terminates.
t
Leases on oil and natural
years, after which they expire unless, prior to
expiration, production is established within the spacing units covering the undeveloped acres. In addition, even if production or
drilling is established during such primary term, if production or drilling ceases on the leased property, the lease typically
terminates, subject to certain exceptions.
gas properties typically have a term of three to fiveff
Any reduction in our operators’ drilling programs, either through a reduction in capita
al expenditures or the unavailability
of drilling rigs, could result in the expiration of existing leases. If the lease governing any of our mineral interests expires or
terminates, all mineral rights revert back to us and we will have to seek new lessees to explore and develop such mineral
interests. If the lease underlying any of our ORRIs expires or terminates, our ORRIs that are derived from such lease will also
terminate. Any such expirations or terminations of our leases or our ORRIs could materially and adversely affect the growth of
our financial condition, results of operations and free cash flow.
Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that may
materially adversely affect our business, finff ancial condition and results of operations.
The drilling activities of the operators of our properties will be subjeu
ct to many risks. For example, we will not be able to
assure our shareholders that wells drilled by the operators of our properties will be productive. Drilling for oil, natural
gas and
NGLs often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce
sufficient oil, natural gas or NGLs to returnt
a profit at then realized prices after deducting drilling, operating and other costs.
The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil, natural gas
or NGL is present or that it can be produced economically. The costs of exploration, exploitation and development activities are
subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a
project. Further, our operators’ drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively
impacted as a result of other facff
tors, including:
t
•
•
•
•
•
•
unusual or unexpected geological formations;
loss of drilling fluid circulation;
title problems;
ff
facility
or equipment malfunctions;
unexpected operational events;
shortages or delivery delays of equipment and services;
41
•
•
compliance with environmental and other governmental requirements; and
adverse weather conditions, including the recent winter storms in February 2021 that adversely affected operator
activity and production volumes in the southern United States, including in the Permian Basin.
t
Any of these risks can cause substant
ial losses, including personal injury or loss of life, damage to or destruction of
property, natural
resources and equipment, pollution, environmental contamination or loss of wells and other regulatory
penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing
a
wells or development wells have lower than anticipated production due to one or more of the factors above
or for any other
ted.
reason, our financial condition, results of operations and free cash flow may be materially adversely affecff
u
Operating hazards and uninsured risks may result in substantial losses to us or our operators, and any losses could
adversely affect our results of operations and free cash flow.
t
t
gas and NGLs, including the risk of fireff
gas, NGLs and formation water, pipe or pipeline failures, abnormally pressured forma
The operations of our operators will be subject to all of the hazards and operating risks associated with drilling for and
, explosions, blowouts, surface cratering, uncontrollable flows
production of oil, natural
and
ff
of oil, natural
gas leaks and ruptures or discharges of toxic gases. In addition, their
environmental hazards such as oil and NGL spills, natural
operations will be subjeu
ct to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential
underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in
resources
substantial losses to our operators due to injury or loss of life, severe damage to or destruction of property, natural
and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties,
suspension of operations and repairs required to resume operations.
ff
tions, casing collapses
a
t
t
Competition in the oil and natural gas industry is intense, which may adversely affect our and our operators’ ability to
succeed.
t
The oil and natural
gas industry is intensely competitive, and the operators of our properties compete with other
companies that may have greater resources. Many of these companies explore for and produce oil, natural gas and NGLs, carry
on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In
addition, these companies may have a greater abia lity to continue exploration activities during
gas and
NGL market prices. Our operators’ larger competitors may be abla e to absorb
the burden of present and future federal, state,
local and other laws and regulations more easily than our operators can, which would adversely affect our operators’
competitive position. Our operators may have fewer finff ancial and human resources than many companies in our operators’
industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural
gas properties.
Furthermore, the oil and gas industry has experienced recent consolidation amongst some operators, which has resulted in
certain instances of combined companies with larger resources. Such combined companies may compete against our operators
or, in the case of consolidation amongst our operators, may choose to focus their operations on areas outside of our properties.
In addition, we face competition in identifying and acquiring additional properties and reserves. See “Our failure to successfully
identify, complete and integrate acquisitions could adversely affect our growth and results of operations.”
periods of low oil, natural
d
a
t
t
Title to the properties in which we have an interest may be impaired by title defects.
We are not required to, and under certain circumstances we may elect not to, incur the expense of retaining lawyers to
examine the title to our royalty and mineral interests. In such cases, we would rely upon
the judgment of oil and gas lease
brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before acquiring a
specific royalty or mineral interest. The existence of a material title deficiency can render an interest worthless and can
materially adversely affect our results of operations, financial condition and freeff
cash floff w. No assurance can be given that we
will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has a greater risk of title
defects than developed acreage. If there are any title defects in properties in which we hold an interest, we may suffer a
financial loss.
u
We rely on a fewff
key individuals whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of individuals. We rely on our
gas industry, relationships within the industry and experience in identifying,
founders for their knowledge of the oil and natural
evaluating and completing acquisitions. The loss of their services could adversely affect our business. In particular, the loss of
the services of one or more members of our executive team could disrupt our business. Further, we do not maintain “key
person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any
losses resulting from the death of these key individuals.
t
42
Loss of our or our operators’ information and computer systems, including as a result of cyber attacks, could materially
and adversely affect our business.
t
l forff
ity to automatically process commercial
We and our operators rely on electronic systems and networks to control and manage our respective businesses. If any of
any reason, including as a result of a cyber attack, or create erroneous information in
such programs or systems were to faiff
possible consequences could be significant, including loss of
our or our operators’ hardware or software network infrastructure,
communication links and inabila
transaction or engage in similar automated or
computerized business activities. Although we have multiple layers of security to mitigate risks of cyber attacks, cyber attacks
on business have escalated in recent years. Moreover, our operators are becoming increasingly dependent on digital
technologies to conduct certain exploration, development, production and processing activities, including interpreting seismic
data, managing drilling rigs, production activities and gathering systems, conducting reservoir modeling and estimating
reserves. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber
security threats. If our operators become the target of cyber attacks of information security breaches, their business operations
may be substantially disrupted, which could have an adverse effect on our results of operations. In addition, our efforts to
monitor, mitigate and manage these evolving risks may result in increased capita
al and operating costs, but there can be no
assurance that such efforts
will be sufficient to prevent attacks or breaches from occurring.
ff
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may
adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations.
If any of these events occur, the resulting political instabila
oil,
gas and NGLs, potentially putting downward pressure on demand for our operators’ services and causing a reduction in
natural
t
integral
our revenues. Oil, natural
insurance
to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Costs forff
and other security may increase as a result of these threats, and some insurance coverage may become more difficul
t to obtain,
if availablea
es could be direct targets of terrorist attacks, and, if infrastructuret
ity and societal disruption could reduce overall demand forff
gas and NGL related faciliti
at all.
ff
ff
t
A deterioration in general economic, business, political or industry conditions, such as those beginning in the firff st
quarter of 2020, has materially adversely affected, and any further deterioration would materially adversely affect our
results of operations, financial condition and free cash flow.
Recently, concerns over global economic conditions, energy costs, geopolitical issues, the impacts of the COVID-19
ity and cost of credit and slow economic growth in the United States have contributed to
pandemic, inflation, the availabila
significantly reduced economic activity and diminished expectations for the global economy. Additionally, recent acts of protest
and civil unrest have caused economic and political disruption in the United States. Meanwhile, continued hostilities in the
Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the
economies of the United States and other countries. Concerns about global economic growth have had a significant adverse
impact on global finaff
ncial markets and commodity prices. An oversupply of crude oil in 2020 has led to a severe decline in
worldwide oil prices. If the economic climate in the United States or abroad continues to deteriorate, worldwide demand for
petroleum products could furthe
gas and NGLs from our properties
are sold, affect the ability of our operators to continue operations and ultimately materially adversely impact our results of
operations, financial condition and free cash flow.
r diminish, which could impact the price at which oil, natural
ff
t
Risks Related to Environmental and Regulatory Matters
Conservation measures, technological advances and increasing attention to environmental, social and governance
(“ESG”) matters could materially reduce demand for oil, natural gas and NGLs, availability of capital and adversely
affect our results of operations and the trading market for shares of our Class A common stock.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural
t
and NGLs, technological advances in fuel economy and energy-generation devices could reduce demand for oil, natural
NGLs. The impact of the changing demand for oil, natural
effect on our business, financial condition, results of operations and free cash flow.
gas
gas and
gas and NGL services and products may have a material adverse
t
t
It is also possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing
to own shares of our Class A common stock, adversely affecting the market price of our Class A common stock. For example,
certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity
in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market
t
returns
indices. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university
43
ff
endowments and family foundat
ions, have stated policies to disinvest in the oil and gas sector based on their social and
environmental considerations. Furthermore, organizations that provide information to investors on corporate governance and
related matters have developed ratings processes forff
evaluating companies on their approach to ESG matters. Such ratings are
ESG ratings may lead to increased
used by some investors to inform their investment and voting decisions, and unfavorablea
negative investor sentiment toward us. Certain other stakeholders have also pressured commercial and investment banks to stop
financing oil and gas and related infrastructuret
projects. Such developments, including environmental activism and initiatives
aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and
gas companim
es, including ours and also adversely affect our availability of capia tal.
Oil, natural gas and NGL operations are subject to various governmental laws and regulations. Compliance with these
laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our
operators incurring significant liabilities, either of which may impact our operators’ willingness to develop our interests.
gas and NGLs. In addition, the production, handling, storage and transportation of oil, natural
Our operators’ operations on the properties in which we hold interests are subject to various federal, state and local
governmental regulations that may change from time to time in response to economic and political conditions. Matters subject
to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes,
ilities, the spacing of wells, unitization and
plugging and abandonment of wells, maintenance and decommissioning of other facff
pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on
ity to conserve supplies of
production by restricting the rate of flow of oil and natural
oil, natural
gas and NGLs, as well
t
gas and NGL wastes, by-products thereof and other substances and
as the remediation, emission and disposal of oil, natural
gas and NGL operations are subject to regulation under federal, state
materials produced or used in connection with oil, natural
and local laws and regulations primarily relating to protection of worker health and safety,t
resources and the
environment. Failure to comply with these laws and regulations may result in the assessment of sanctions on our operators,
additional pollution controls and
including administrative, civil or criminal penalties, permit revocations, requirements forff
injunctions limiting or prohibiting some or all of our operators’ operations on our properties. Moreover, these laws and
regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control and
waste management.
gas wells below actual production capac
t
t
natural
t
t
a
t
Laws and regulations governing exploration and production may also affect production levels. Our operators must comply
with federal and state laws and regulations governing conservation matters, including, but not limited to:
•
•
•
•
•
provisions related to the unitization or pooling of the oil and natural
t
gas properties;
the establishment of maximum rates of production from wells;
the spacing of wells;
the plugging and abaa ndonment of wells; and
the removal of related production equipment.
Additionally, federal and state regulatory authorities may expand or alter appl
a
compliance with which may require increased capita
transporters may attempt to pass on such costs to our operators, which in turn could affecff
al costs for third-party oil, natural
icable pipeline-safety laws and regulations,
gas and NGL transporters. These
ity on our properties.
t profitabila
t
Our operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets.
f those
To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs off
pipelines and with federal policies related to the use of interstate capac
ity.
a
t
Our operators may be required to make significant expenditures
to comply with the laws and regulations described above
and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. We believe the
trend of more expansive and stricter environmental legislation and regulations will continue. For example, following the
election of President Biden and a Democratic majoa rity in both houses of Congress, it is possible that our operators may be
subjeu
estrictions, particularly with regards to hydraulic fracturing, permitting and
GHG emissions. Please read “Item 1—Business—Regulation of Environmental and Occupational Safety and Health Matters”
for a description of the laws and regulations that affect our operators and that may affect us. These and other potential
regulations could increase the operating costs of our operators and delay production and may ultimately impact our operators’
ability and willingness to develop our properties.
ct to greater environmental, health and safety r
t
44
Federal and state legislative and regulatory initiatives relating to hydraulic frac
incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.
turing could result in our operators
ff
Our operators engage in hydraulic fracturing, which is a common practice that is used to stimulate production of
hydrocarbons from tight formations, including shales. The process involves the injection of water, sand and chemicals under
pressure into formations to fracture the surrounding rock and stimulate production. Currently, hydraulic fracturing is generally
exempt from regulation under the SDWA Underground Injection Control program and is typically regulated by state oil and gas
commissions or similar agencies.
ff
However, several fede
ral agencies have asserted regulatory authority over certain aspects of the process. For example, in
June 2016, the EPA published an effluent limit guideline final rulerr
onshore
unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Also, from time to time,
legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to
require disclosure of the chemicals used in the hydraulic fracturing process. This or other fede
ral legislation related to hydraulic
fracturing may be considered again in the future, though we cannot predict the extent of any such legislation at this time.
prohibiting the discharge of wastewater fromff
ff
Moreover, some states and local governments have adopted, and other governmental entities are considering adopting,
regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing
operations, including states in which our properties are located. For example, Texas, Colorado and North Dakota, among others,
have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements
on hydraulic fracturing operations. In April 2019, Colorado adopted Senate Bill 19-181, which makes sweeping changes in
Colorado oil and gas law, including among other matters, requiring the COGCC to prioritize public health and environmental
concerns in its decisions, instructing the COGCC to adopt rules to minimize emissions of methane and other air contaminants,
and delegating considerable new authority to local governments to regulate surface impacts. In keeping with SB 19-181, the
COGCC in November 2020 adopted revisions to several regulations to increase protections for public health, safety,t welfare,
cks (2,000 feet, instead
wildlife, and environmental resources. Most significantly, these revisions establia
of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural
gas at new or
existing wells across the state, each subjeu
ct to only limited exceptions. Some local communities have adopted, or are
considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks. States could also elect to
prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city
ordinances, may restrict drilling in general and/or hydraulic fracturing in particular.
sh more stringent setbat
t
Separately, several state and federal agencies have examined a possible connection between hydraulic fracturing related
activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic
activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and
induced seismicity. The United States Geological Survey has identified eight states, including Oklahoma and Texas, with areas
of increased rates of induced seismicity that could be attributed to fluff
id injen ction or oil and gas extraction.
In addition, a number of lawsuits have been filff ed, most recently in Oklahoma, alleging that disposal well operations have
caused damage to neighboring properties or otherwise violated state and fede
ral rules regulating waste disposal. In response to
these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the
permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such
wells. In some instances, regulators may also order that disposal wells be shut in.
ff
Increased regulation and attention given to the hydraulic fracturing process, including the disposal of produced water
gas
turing techniques in areas where we own mineral and royalty interests.
our operators in the
our
ff
The adoption of any federal, state or local laws or the implm ementation of regulations
could potentially cause a decrease in our operators’ completion of new oil and natural gas wells
to our interests, which could have a material adverse
gathered from drilling and production activities, could lead to greater opposition to, and litigation concerning, oil, natural
and NGL production activities using hydraulic fracff
Additional legislation or regulation could also lead to operational delays or increased operating costs forff
production of oil, natural gas and NGLs, including from the development of shale plays, or could make it more difficult forff
operators to perform hydraulic fract
t
uring.
t
regarding hydraulic fract
uring
on our properties and an associated decrease in the production attributablea
on our business, financial condition and results of operations.
ff
effect
ff
t
Restrictions on the ability of our operators to obtain water may have an adverse effect on our financial condition, results
of operations and free cash flow.
Water is an essential component of deep shale oil, naturt al gas and NGL production during both the drilling and hydraulic
fracturing processes. Over the past several years, parts of the country, and in particular the western United States, have
experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the
45
use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply.
Such conditions may be
exacerbated by climate change. If our operators are unable to obtain water to use in their operations from local sources, or if our
operators are unable to effectively utilize flowback water, they may be unable to economically drill forff
or produce oil, natural
our properties, which could have an adverse effect on our financial condition, results of operations and free
gas and NGLs fromff
cash flow.
u
A series of risks arising out of the threat of climate change could result in increased operating costs, limit the areas in
which oil and natural gas production may occur, and reduce demand for the oil, natural gas and NGLs that our
operators produce.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. As a
gas exploration and production customers are subject to a
s and
result, our operations as well as the operations of our oil and natural
series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuel
emission of GHGs.
ff
t
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However,
President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive
orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a
pollutant under the CAA, the EPA has adopted regulations that, among other things, establia
sh construction and operating permit
reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG
gas system sources in the United States, and together with the DOT,
emissions from certain petroleum and natural
implementing GHG emissions limits on vehicles manufactured forff
operation in the United States. The regulation of methane
from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised
prior regulations to rescind certain methane standards and remove the transmission and storage segments fromff
the source
category for certain regulations. However, President Biden has signed an executive order calling for the suspension, revision, or
rescission of the September 2020 rule, and the reinstatement or issuance of methane emissions standards for new, modified, and
existing oil and gas facilities.
t
Separately, various states and groups of states have adopted or are considering adopting legislation, regulation or other
regulatory initiatives that are focused on such areas as GHG cap a
nd trade programs, carbon taxes, reporting and tracking
a
programs, and restriction of emissions. At the international level, the United Nations-sponsored "Paris Agreement" requires
member states to submit non-binding, individually-determined reduction goals known
as Nationally Determined Contributions
(“NDCs”) every five years after 2020. Although the United States had withdrawn from the Paris agreement, President Biden
has signed executive orders recommitting the United States to the agreement and calling on the federal government to develop
the United States’ NDC. However, the impacts of these executive orders and the terms of any legislation or regulation to
implement the United States’ commitment remain unclear at this time.
k
ff
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted
in increasing political risks in the United States, including action taken by President Biden with respect to his climate change
related pledges. On January 27, 2021, President Biden issued an executive order that calls for substantial action on climate
change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination
industry, and increased emphasis on climate-related risks across government agencies
of subsidies provided to the fossil fuel
and economic sectors. The Biden Administration has also issued orders temporarily suspending the issuance of authorizations,
and suspending the issuance of new leases pending a study, for oil and gas development on federal lands. Substantially all of
our mineral interests are located on private lands, but we cannot predict the full impact of these developments or whether the
Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may
include the imposition of more restrictive requirements for the establishment of pipeline infrastructuret
or the permitting of LNG
export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also
increasing as a number of cities and other local governments have sought to bring suit against the largest oil and natural
gas
companies in state or federal court, alleging among other things, that such companies created public nuisances by producing
fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change
for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
t
ff
There are also increasing financial risks forff
fossil fuel producers as shareholders currently invested in fossil-fuel energy
to shift some or all of their investments into non-fossil fuel related sectors. Institutional
companies may elect in the future
lenders who provide financing to fossil
fuel energy companies also have become more attentive to sustainable lending practices
ff
and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial
institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector.
Recently, President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, the
Federal Reserve announced that is has joined the Network forff Greening the Financial System, a consortium of financial
46
regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financing for
fossil fuel
energy companies could result in the restriction, delay or cancellation of drilling programs or development or
production activities.
ff
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other
gas sector or otherwise
regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural
gas or generate the GHG emissions could result in increased
restrict the areas in which this sector may produce oil and natural
gas, which could reduce the
costs of compliance or costs of consuming, and thereby reduce demand for oil and natural
gas operators
profitability of our interests. Additionally, political, litigation and financial risks may result in our oil and natural
restricting or cancelling production activities, incurring liability for infrastructuret
damages as a result of climatic changes, or
impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests.
One or more of these developments could have a material adverse effect on our business, financial condition and results of
operation.
t
t
t
t
Potential future legislation may generally affect the taxation of natural gas and oil exploration and development
companies such as our operators, and may adversely affect our operators’ operations on the properties in which we hold
interests, which, in turn, could adversely affect our results of operation and free cash flow.
In past years, federal legislation has been proposed that would, if enacted into law, make significant changes to tax laws,
including to certain key U.S. federal income tax provisions currently available to natural
gas and oil exploration and
development companies such as our operators. For example, President Joe Biden has set forth several tax proposals that would,
if enacted into law, make significant changes to U.S. tax laws. Such proposals include, but are not limited to, (i) an increase in
s. Congress could
the U.S. income tax rate applicablea
consider some or all of these proposals in connection with tax reform to be undertaken by the Biden administration.
It is
unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The
passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws could
adversely affect our operators’ operations on the properties in which we hold interests, which, in turn, could adversely affect
our results of operation and freeff
to corporations and (ii) the elimination of tax subsidies forff
cash flow.
fossil fuel
ff
t
Additional restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our
operators’ ability to conduct drilling activities.
In the United States, the ESA restricts activities that may affect endangered or threatened species or their habitats. Similar
ird Treaty Act (the “MBTA”). To the extent species that are
protections are offered to migratory birds under the Migratory Brr
listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where our operators operate, our
operators’ abilities to conduct or expand operations could be limited, or our operators could be forced to incur material
additional costs. Moreover, our operators’ drilling activities may be delayed, restricted or precluded in protected habitat areas or
during certain seasons, such as breeding and nesting seasons.
In addition, as a result of one or more settlements approved by the U.S. Fish & Wildlife Service (the “FWS”), the agency
was required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by
the end of the FWS’ 2017 fiscal year. The FWS did not make that deadline; however, review is reportedly ongoing. The
designation of previously unidentified endangered or threatened species-such as the dunes sagebrusrr h lizard, lesser prairie
chicken or greater sage grouse-could cause our operators’ operations to become subject to operating restrictions or bans, and
limit future
habitat
ff
areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially
restrict use of or access to federal, state and private lands.
development activity in affected areas. The FWS and similar state agencies may designate critical or suitablea
Risks Related to Our Financial and Debt Arrangements
Our derivative activities could result in financial losses and reduce earnings.
From time to time in the past we have used, and in the future we may use, derivative instruments for a portion of our
future oil, natural gas and NGL production, including fixed price swaps, collars and basis swaps, to mitigate the risk and
resulting impact of commodity price volatility. However, these hedging activities may not be as effective as we intend in
reducing the volatility of our cash flows and, if entered into, are subject to the risks that the terms of the derivative instruments
will be impem rfect,
a counterparty may not perform its obligations under a derivative contract, there may be a change in the
expected differential between the underlying commodity price in the derivative instrument and the actual price received, our
hedging policies and procedures may not be properly followed and the steps we take to monitor our derivative financial
nts may not detect and prevent violations of our risk management policies and procedures, particularly if deception or
r
instrume
ff
47
other intentional misconduct is involved. Further, we may be limited in receiving the full benefit of increases in oil, natural
gas
and NGL prices as a result of these hedging transactions. The occurrence of any of these risks could prevent us from realizing
the benefit of a derivative contract. Further, our hedging activities are not likely to mitigate the entire exposure of our
gas or oil derivative contracts in place as of December 31, 2020
operations to commodity price volatility. We had no natural
and 2019. For the years ended December 31, 2019 and 2018, we recorded a loss on commodity derivative instruments, net of
$0.6 million and a gain of $0.4 million, respectively. To the extent we do not hedge against commodity price volatility, or our
hedges are not effective, our results of operations and financial position may be diminished.
t
t
Our revolving credit facility has substantial restrictions and financial covenants that may restrict our business and
financing activities and our ability to declare dividends.
The operating and financial restrictions and covenants in our revolving credit facility restrict, and any future financing
al needs, engage, expand or pursue our business
agreements likely will restrict, our ability to finance future operations or capita
activities or pay dividends. Our revolving credit facility restricts, and any future financing agreements likely will restrict, our
ability to, among other things:
•
•
•
•
incur indebtedness;
issue certain equity securities, including preferred equity securities;
incur certain liens or permit them to exist;
engage in certain fundam
ff
ental changes, including mergers or consolidations;
• make certain investments, loans, advances, guarantees and acquisitions;
•
•
•
sell or transfer assets;
enter into sale and leaseback transactions;
pay dividends to or redeem or repurchase shares fromff
our shareholders;
• make certain payments of junior indebtedness;
•
•
•
enter into transactions with our affilff
iates;
enter into certain restrictive agreements; and
enter into swap agreements and hedging arrangements.
ed by the levels of freeff
Our revolving credit facility restricts our ability to pay dividends to our shareholders or to repurchase shares of our Class
A common stock. We also are required under our revolving credit facility to comply with, as of the most recently completed
fiscal quarter, (i) a ratio of total net funded debt to consolidated EBITDA not to exceed 4.00 to 1.00, and (ii) a current ratio of
not less than 1.00 to 1.00. Our ability to comply with these restrictions and covenants in the future is uncertain and will be
cash floff w and events or circumstances beyond our control, such as a downturn in our business or
affect
ff
gas and NGL prices. If we violate any of the restrictions, covenants, ratios or
the economy in general or reduced oil, natural
tests in our revolving credit facility, a significant portion of our indebtedness may become immediately due and payablea
, our
ability to pay dividends to our shareholders will be inhibited and our lenders’ commitment to make further loans to us may
terminate. We might not have, or be abla e to obtain, sufficient funds to make these accelerated payments. In addition, our
obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our
indebtedness under our revolving credit facff
ility, the lenders can seek to foreclose on our assets.
t
The borrowings under our revolving credit facility expose us to interest rate risk.
We are exposed to interest rate risk associated with borrowings under the our revolving credit facility. Our revolving
credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted London Inter-Bank
Offered Rate ("LIBOR") rate plus an applicable margin. The applicablea margin is based on utilization of our revolving credit
facility and ranges fromff
(a) in the case of adjusted base rate loans, 0.750% to 1.750% and (b) in the case of adjusted LIBOR
rate loans, 1.750% to 2.750%. LIBOR tends to fluctuate based on multiple facts, including general short-term interest rates,
rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank
48
market and general economic conditions. If interest rates increase, so will our interest costs, which may have a material adverse
effect on our business, financial conditions and results of operations.
On July 27, 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to
stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating
LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the
Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index. It is not
shment of alternative reference rates in the United
possible to predict the effect of these changes, other reforms or the establia
States or elsewhere.
Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.
Our existing and futuret
indebtedness could have important consequences to us, including:
•
•
•
•
our ability to obtain additional finff ancing, if necessary, for working capita
purposes may be impaired, or such finff ancing may not be availablea
on terms acceptablea
t
to us;
al, capital expenditures,
acquisitions or other
covenants in our existing and futuret
our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunit
t
credit and debt arrangements will require us to meet financial tests that may affecff
ies;
t
our access to the capita
al markets may be limited;
our borrowing costs may increase;
• we will need a substantial portion of our free cash flow to make principal and interest payments on our indebtedness,
reducing the funds
dividends to our shareholders; and
ff
that would otherwise be available forff
operations, future business opportunities and payment of
•
our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturnt
in our business or the economy generally.
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating
performance, which will be affect
tors,
some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness,
al
d to take actions such as reducing or delaying business activities, acquisitions, investments and/or capita
ff
we will be force
expenditures,
selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy
t
protection. We may not be able to effecff
ed by prevailing economic conditions and financial, business, regulatory and other facff
t any of these remedies on satisfactory terms or at all.
ff
Risks Related to Our Class A Common Stock
Brigham Minerals is a holding company. Brigham Minerals’ sole material asset is its equity interest in Brigham LLC
and it is accordingly dependent upon distributions from Brigham LLC to pay taxes, cover its corporate and other
overhead expenses and pay any dividends on our Class A common stock.
t
Brigham Minerals is a holding company and has no material assets other than its equity interest in Brigham LLC. Please
Brigham Minerals has no independent means of generating
see “Item 1—Business—Overview—Our Corporate Structure.”
revenue. To the extent Brigham LLC has availaba le cash, Brigham LLC is required to make (i) generally pro rata distributions to
all its unitholders, including to Brigham Minerals, in an amount generally intended to allow such holders to satisfy their
respective income tax liabilities with respect to their allocable share of the income of Brigham LLC, based on certain
l tax
assumptim ons and conventions, provided that the distribution will be sufficien
liabilities and (ii) non pro rata payments to Brigham Minerals in an amount sufficient to cover its corporate and other overhead
expenses. In addition, as the sole managing member of Brigham LLC, we will cause Brigham LLC to make pro rata
distributions to all of its unitholders, including to Brigham Minerals, in an amount sufficient to allow us to fund dividends to
our stockholders in accordance with our dividend policy, to the extent our board of directors declares such dividends.
Therefore, although we have paid dividends to our stockholders in the past and expect to pay dividends on our Class A common
stock in amounts determined from time to time by our board of directors in the future, our ability to do so may be limited to the
extent Brigham LLC and its subsidiaries are limited in their ability to make these and other distributions to us, including due to
and Brigham LLC or its subsidiaries are
the restrictions under our revolving credit facility. To the extent that we need funds
t to allow Brigham Minerals to satisfy its actuat
ff
ff
49
restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements,
or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and finaff
ncial condition.
The requirements of being a public company, including compliance with the reporting requirements of the Exchange
Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract
management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a public company, we need to comply with new laws, regulations and requirements, certain corporate governance
provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the New York Stock Exchange
(the "NYSE"), with which we were not required to comply as a private company. Complying with these requirements occupies
a significant amount of time of our board of directors and management and significantly increases our costs and expenses. We
are required to, among other things, institute a more comprehensive compliance function, comply with rules promulgated by the
sh new internal policies,
NYSE; prepare and distribute periodic public reports in compliance with federal securities laws; establia
such as those relating to insider trading, and involve and retain to a greater degree outside counsel and accountants in the above
activities.
Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act for our fiscal year ending
December 31, 2020, we are not required to have our independent registered public accounting firm attest to the effectiveness of
our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the
meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered
public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year
ending December 31, 2024. Once it is required to do so, our independent registered public accounting firm may issue a report
that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or
reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we
may be unablea
to comply with these requirements in a timely or cost-effective manner.
In addition, being a public company subject to these rules and regulations makes it more diffiff cult and more expensive for
us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or
incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more diffiff cult for us to attract and
retain qualified individuals to serve on our board of directors or as executive officers.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our
financial results or prevent fraud. If one or more material weaknesses emerge related to financial reporting, or if we
otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately
report our financial results could be adversely affected. As a result, current and potential stockholders could lose
confidence in our financial reporting, which would harm our business and the trading price of our Class A common
stock.
ff
ff
rr
orff
us to provide reliabla e financ
Effective internal controls are necessary f
ial reports, prevent fraud and operate successfully
as a public company. If we cannot provide reliabla e financ
ial reports or prevent fraud, our reputation and operating results would
be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will
be able to maintain adequate controls over our financial processes and reporting in the future, that we will be able to comply
with our obligations under Section 404 of the Sarbanes-Oxley Act, or that we will not identify material weaknesses related to
our financial reporting. For example, in connection with the preparation and review of our unaudited consolidated financial
statements forff
the nine months ended September 30, 2018, our management identified certain material weaknesses which have
since been remediated. If one or more material weaknesses emerge related to financial reporting in the future, or if we otherwise
sh and maintain effective internal control over financial reporting, our operating results and ability to meet our
fail to establia
reporting obligations may be adversely affected and we may be subject to adverse regulatory consequences. Ineffective internal
controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative
effeff ct on the trading price of our Class A common stock. See "Item 7—Management’s Discussion and Analysis of Financial
Condition and Results of Operations—Internal Controls and Procedures.”
Our Sponsors have the ability to direct the voting of a substantial portion of the voting power of our common stock, and
their interests may conflict with those of our other stockholders.
Holders of shares of our Class A common stock and Class B common stock vote together as a single class on all matters
presented to our stockholders for their vote or approval, except as otherwise required by appl
icable law or our certificate of
incorporation. As of December 31, 2020, our Sponsors beneficially own, on a combined basis, none of our outstanding shares
of Class A common stock and approximately 72.9% of our shares of Class B common stock, representing 16.9% of our
combined economic interest and voting power. As a result, this concentration of ownership allows our Sponsors to have
a
50
significant influence over matters requiring stockholder approva
l, may deter hostile takeovers and may make it less likely that
other holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The
interests of our Sponsors with respect to matters potentially or actually involving or affecting us, such as future acquisitions,
financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other
stockholders.
a
Furthermore, we are party to a stockholders’ agreement with our Sponsors. The stockholders’ agreement provides each of
our Sponsors with the right to designate a certain number of nominees to our board of directors, subject to certain ownership
requirements in our common stock. Our Sponsors’ concentration of stock ownership may also adversely affect the trading price
of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with significant
stockholders.
Furthermore, while we believe that our Sponsor’s ownership interests in us provide them with an economic incentive to
assist us to be successful, our Sponsors are not subject to any obligation to maintain their ownership interest in us. Our
Sponsors may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce their ownership interest in us,
such as in the case of certain sales of our stock by our Sponsors in 2020. Such actions could adversely affect our ability to
successfully implement our business strategies, which could adversely affect our business, financial condition and results of
operations.
Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with
us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time
or pursuing business opportunities.
t
t
Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold
positions of responsibility with other entities (including Yorktown- and Pine Brook-affiliated entities) that are in the business of
identifying and acquiring oil and natural
gas properties. For example, one of our directors (Mr. Keenan) is a Managing Member
of Yorktown and one of our directors (Mr. Stoneburner) is a Managing Director of Pine Brook, both of which are in the
business of investing in oil and natural
gas companies with independent management teams that also seek to acquire oil and
gas properties. In addition, Mr. Brigham, our executive chairman, is involved with certain other entities involved in the
natural
t
including Brigham Exploration Company, Atlas Permian Water, Atlas Permian Sand, Brigham
oil and gas industry,
Development and Anthem Ventures.
s that
are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be
appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these
existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting
them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more
appropriate forff
other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to
us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and
the potential conflicts of interest of which our stockholders should be aware, see “Item 13—Certain Relationships and Related
Transactions, and Director Independence.”
The existing positions held by these directors may give rise to fidff ud ciary orr
r other dutie
d
t
Our Sponsors and their affiliates are not limited in their ability to compete with us, and the corporate opportunity
provisions in our amended and restated certificate of incorporation could enable our Sponsors to benefit from corporate
opportunities that might otherwise be available to us.
Our governing documents provide that our Sponsors and their affiliates (including portfolio investments of our Sponsors
and their affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us
and that we renounce any interest or expectancy in any business opportunity that may be from time to time presented to our
Sponsors or their respective affiliates. In particular, subject to the limitations of applicable law, our amended and restated
certificate of incorporation, among other things:
•
•
permits our Sponsors and their affiliates and our directors to conduct business that competes with us and to make
investments in any kind of property in which we may make investments; and
provides that if our Sponsors or their affiliates or any director or officer of one of our affiliates, our Sponsors or their
affiliates who is also one of our directors becomes aware of a potential business opportunity, transaction or other
matter, they will have no dutd y to communicate or offer that opportunit
y to us.
t
Our Sponsors or their affiliates may become aware, from time to time, of certain business opportunities (such as
acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we
may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to
51
compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be
more expensive for us to pursue. In addition, our Sponsors and their affiliates may dispose of oil and natural
gas properties or
other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our
renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our Sponsors
and their affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such
parties forff
their own benefit rather than for ours. Please see Exhibit 4.7 to this Annual Report on Form 10-K “Description of
Brigham Minerals, Inc.’s Class A common stock.”
t
Each of our Sponsors is an establia
gas industry and has resources greater than ours,
shed participant in the oil and natural
which may make it more difficult forff
us to compete with our Sponsors with respect to commercial activities as well as for
potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand,
and our Sponsors, on the other hand, will be resolved in our favor. As a result, competition from our Sponsors and their
affiliates could adversely impact our results of operations.
t
Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law,
contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market
their
price of our Class A common stock and could deprive our investors of the opportunity to receive a premium forff
shares.
Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without
ng any series, and fix the rights,
stockholder approval in one or more series, designate the number of shares constituti
preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption,
redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, it
a third party to acquire us. In addition, some provisions of our amended and restated certificate of
could be more difficul
a third party to acquire control of us, even if
incorporation and amended and restated bylaws could make it more difficult forff
the change of control would be beneficial to our stockholders. Among other things, our amended and restated certificate of
incorporation and amended and restated bylaws:
t forff
ff
t
•
•
•
•
•
•
•
•
•
establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates forff
election as directors or new business to be brought before meetings of our stockholders;
provide that the authorized number of directors constituti
of the board of directors;
t
ng our board of directors may be changed only by resolution
provide that all vacancies, including newly created directorships, may, except as otherwise required by law, the terms
of the stockholders’ agreement or, if applicablea
, the rights of holders of a series of our preferred stock, be filled by the
a
affirmative vote of a majori
ty of our directors then in office, even if less than a quorum;
provide that our bylaws can be amended by the board of directors;
provide that any action required or permitted to be taken by our stockholders must be effected at a dulyd
or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such
stockholders, subject to the rights of the holders of any series of our preferred stock with respect to such series;
called annual
provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of not
less than 66 2/3% of our then outstanding shares of common stock;
provide that special meetings of our stockholders may only be called by our board of directors pursuant to a resolution
adopted by the affirmative vote of a majority of the members of the board of directors serving at the time of such vote;
provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in
number as possible, serving staggered three-year terms, other than directors that may be elected by holders of our
preferred stock, if any;
provide that the affirmff
of common stock entitled to vote generally in the election of directors, voting together as a single class, shall be
required to remove any or all of the directors from office, and such removal may only be forff
ative vote of the holders of not less than 66 2/3% in voting power of all then outstanding shares
“cause”; and
•
prohibit cumulative voting on all matters.
52
Furthermore, the terms of our amended and restated certificate of incorporation and amended and restated bylaws are
subject to the terms of the stockholders’ agreement. See “Item 13—Certain Relationships and Related Transactions, and
Director Independence.”
Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the
sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which
could limit our stockholders’ ability to obtain a favorabl
e judicial forum for disputes with us or our directors, officers,
employees or agents.
ff
ff
a
Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an
alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by appl
icable law, be the
sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of
iary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action
breach of a fiduc
asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our amended and restated
certificate of incorporation or our amended and restated bylaws or (iv) any action asserting a claim against us that is governed
by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the
indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares
of our capita
al stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of
incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a
claim in a judicial forum that it finff ds favorablea
for disputes with us or our directors, officers, employees or agents, which may
discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and
restated certificate of incorporation inappli
in respect of, one or more of the specified types of actions
or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could
adversely affecff
t our business, financial condition or results of operations.
to, or unenforceablea
cablea
a
Our ability to pay dividends to our stockholders may be limited by our holding company structure, contractual
restrictions and regulatory requirements.
t to allow Brigham Minerals to satisfy its actuat
Brigham Minerals is a holding company and has no material assets other than its ownership of Brigham LLC Units, and
Brigham Minerals does not have any independent means of generating revenue. To the extent Brigham LLC has availabla e cash,
Brigham LLC is required to make (i) generally pro rata distributions to all its unitholders, including to Brigham Minerals, in an
amount generally intended to allow such holders to satisfy their respective income tax liabilities with respect to their allocable
share of the income of Brigham LLC, based on certain assumptim ons and conventions, provided that the distribution will be
l tax liabilities and (ii) non-pro rata payments to Brigham Minerals in an
ff
sufficien
amount sufficient to cover its corporate and other overhead expenses. In addition, as the sole managing member of Brigham
LLC, Brigham Minerals will cause Brigham LLC to make pro rata distributions to all of its unitholders, including to Brigham
Minerals, in an amount sufficient to allow it to fund dividends to its stockholders in accordance with its dividend policy, to the
extent its board of directors declares such dividends. Brigham LLC is a distinct legal entity and may be subject to legal or
contractual restrictions that, under certain circumstances, may limit Brigham Minerals ability to obtain cash from it. If Brigham
LLC is unable to make distributions, we may not receive adequate distributions, which could materially and adversely affect
our free cash flow and finaff
ncial position and our ability to fund
any dividends.
ff
Although we have paid dividends on our Class A common stock and expect to pay dividends on our Class A common
stock in the future, our board of directors will take into account general economic and business conditions, including our
al requirements, contractual restrictions, including restrictions and covenants
financial condition and results of operations, capita
tors that our board of directors considers relevant in
contained in our debt agreements, business prospects and other facff
determining whether, and in what amounts, to pay such dividends. In addition, our revolving credit facility limits the amount of
distributions that Brigham LLC can make to us and the purposes for which distributions could be made. Accordingly, we may
not be able to pay dividends even if our board of directors would otherwise deem it appropria
te. See “Item 5—Market forff
Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dividend Policy,” “Item
7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements and
Sources of Liquidity” and Exhibit 4.7 to this Annual Report on Form 10-K, “Description of Brigham Minerals, Inc.’s Class A
common stock.”
a
In certain circumstances, Brigham LLC will be required to make tax distributions to the Brigham Unit Holders,
including Brigham Minerals, and such tax distributions may be substantial. To the extent Brigham Minerals receives
tax distributions in excess of its actual tax liabilities and retains such excess cash, the Original Owners would benefit
from such accumulated cash balances if they exercise their Redemption Right.
53
ff
including an assumed individual
Pursuant to the Brigham LLC Agreement, to the extent Brigham LLC has availablea
cash (taking into account existing and
projected capita
al expenditures), Brigham LLC is required to make generally pro rata distributions (which we refer to as “tax
distributions”), to all its unitholders, including Brigham Minerals, in an amount generally intended to allow the Brigham Unit
Holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of Brigham LLC,
based on certain assumptions and conventions, provided that tax distributions will be made sufficien
t to allow Brigham
ts actual tax liabilities. The amount of such tax distributions will be determined based on certain
Minerals to satisfy i
assumptions,
income tax rate, and will be calculated after taking into account other
distributions (including other tax distributions) made by Brigham LLC. Because tax distributions will be made pro rata based
to Brigham Minerals and the assumed
on ownership and due to, among other items, differences between the tax rates applicablea
individual income tax rate used in the calculation and requirements under the applicablea
s that Brigham LLC’s net
taxable income be allocated disproportionately to its unitholders in certain circumstances, tax distributions may significantly
exceed the actual tax liability forff many of the Brigham Unit Holders, including Brigham Minerals. If Brigham Minerals retains
the excess cash it receives, the Original Owners would benefit from any value attributablea
to such accumulated cash balances
upon their exercise of the Redemption Right. However, we expect to use such accumulated cash balances to pay dividends in
respect of our Class A common stock or to take other steps to eliminate any material cash balances. In addition, the tax
distributions Brigham LLC will be required to make may be substantial and may exceed the tax liabilities that would be owed
by a similarly situated corporate taxpayer. Funds used by Brigham LLC to satisfy its tax distribution obligations will not be
available forff
reinvestment in our business, except to the extent Brigham Minerals uses the excess cash it receives to reinvest in
Brigham LLC for additional units.
tax ruler
ff
The U.S. feder
tax attributes and the holder’s tax basis in our stock, which are not necessarily predictable and can change over time.
al income tax treatment of distributions on our Class A common stock to a holder will depend upon our
ff
Distributions of cash or property on our Class A common stock, if any, will constitute dividends for U.S. federal income
our current or accumulated earnings and profits, as determined under U.S. federal income
tax purposes to the extent paid fromff
tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will
be treated as a non-taxable returnt
al to the extent of the non-U.S. holder’s tax basis in our Class A common stock and
the sale or exchange of such common stock. Also, if any holder sells our Class A common stock,
thereafter as capital gain fromff
between the amount realized and the holder’s tax basis in such
the holder will recognize a gain or loss equal to the difference
Class A common stock.
of capita
ff
To the extent that the amount of our distributions is treated as a non-taxable returnt
al as described above, such
distribution will reduce a holder’s tax basis in the Class A common stock. Consequently, such excess distributions will result in
a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder
upon the sale of the Class A common stock or subsequent distributions with respect to such stock. Additionally, with regard to
U.S. corporate holders of our Class A shares, to the extent that a distribution on our Class A shares exceeds both our current and
accumulated earnings and profits and such holder’s tax basis in such shares, such holders would be unable to utilize the
to such holder) with respect to the gain
corporate dividends-received deduction (to the extent it would otherwise be applicablea
resulting fromff
such excess distribution.
of capita
Investors in our Class A common stock are encouraged to consult their tax advisors as to the tax consequences of
receiving distributions on our Class A shares that are not treated as dividends for U.S. federal income tax purposes.
Future sales of shares of our Class A common stock in the public market, or the perception that such sales may occur,
could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities
may dilute your ownership in us.
Certain of our Original Owners own shares of our Class A common stock and, subject to certain limitations and
exceptions, the Original Owners that hold Brigham LLC Units may require Brigham LLC to redeem their Brigham LLC Units
for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock
dividends and reclassification and other similar transactions), and our Original Owners may sell any of such shares of Class A
common stock. As of February 19, 2021, we had outstanding 43,558,494 shares of Class A common stock and 13,167,687
shares of Class B common stock, representing approximately 23.2% of our total outstanding shares. The Sponsors are party to a
registration rights agreement, which requires us to effect the registration of their shares in certain circumstances. See “Item1—
and “Item 13—Certain Relationships and Related Transactions, and Director
Business—Overview—Our Corporate Structure”
Independence.”
t
We have previously filed a registration statement with the SEC on Form S-8 providing for the registration of 5,999,600
ct to the satisfaction
issuance under our equity incentive plan. Subjeu
shares of our Class A common stock issued or reserved forff
54
of vesting conditions, shares registered under the registration statement on Form S-8 will be available for resale immediately in
the public market without restriction.
issuances of our Class A common stock or securities convertible into Class A
We cannot predict the size of future
common stock or the effect, if any, that future
issuances and sales of shares of our Class A common stock will have on the
market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued
in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices
of our Class A common stock.
ff
ff
Our organizational structure confers certain benefits upon the Original Owners that will not benefit the holders of our
Class A common stock to the same extent as it will benefit the Original Owners.
Our organizational structuret
confers certain benefits uponu
the Original Owners that do not benefit the holders of our Class
A common stock to the same extent as it will benefit the Original Owners. Brigham Minerals is a holding company and has no
material assets other than its ownership of Brigham LLC Units. As a consequence, our ability to declare and pay dividends to
the holders of our Class A common stock is subject to the ability of Brigham LLC to provide distributions to us. If Brigham
LLC makes such distributions, the Original Owners will be entitled to receive equivalent distributions from Brigham LLC on a
pro rata basis. However, because we must pay taxes, amounts ultimately distributed as dividends to holders of our Class A
common stock are expected to be less on a per share basis than the amounts distributed by Brigham LLC to the Original
Owners on a per unit basis. This and other aspects of our organizational structuret
may adversely impact the future trading
market for our Class A common stock.
We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common
stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue, without the approval of
our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative
rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors
may determine. The terms of one or more classes or series of our preferred stock could adversely impact the voting power or
value of our Class A common stock. For example, we might grant holders of a class or series of our preferred stock the right to
elect some number of our directors in all events or on the happening of specified events or the right to veto specified
transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of our
preferred stock could affect the residual value of our Class A common stock.
For as long as we are an emerging growth company, we will not be required to comply with certain reporting
requirements, including those relating to accounting standards and disclosure about our executive compensation, that
apply to other public companies.
We are classified as an “emerging growth company” under the Jumpstart Our Business Startups
Act (the "JOBS Act").
For as long as we are an emerging growth company, which may be up tu
full fiscal years, unlike other public companies,
we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the
effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act;
(ii) comply with any new requirements adopted by the Public Company Accounting Oversight Board (the "PCAOB") requiring
mandatory audit firmff
rotation or a supplement to the auditor’s report in which the auditor would be required to provide
additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosure regarding
executive compensation required of
(iv) hold nonbinding advisory votes on executive
compensation. We may remain an emerging growth company until December 31, 2024, although we will lose that status sooner
if we have more than $1.07 billion of revenues in a fisca
l year, have more than $700 million in market value of our Class A
common stock held by non-affiliates, or issue more than $1 billion of non-convertible debt over a three-year period.
larger public companies; or
o fiveff
ff
t
To the extent that we rely on any of the exemptim ons available to emerging growth companies, you will receive less
information about
our executive compensation and internal control over financial reporting than issuers that are not emerging
growth companies. If some investors find our Class A common stock to be less attractive as a result, there may be a less active
trading market for our Class A common stock and our stock price may be more volatile.
a
If securities or industry analysts adversely change their recommendations regarding our Class A common stock or if
our operating results do not meet their expectations, our stock price could decline.
The trading market for our Class A common stock will be influenc
ed by the research and reports that industry or securities
analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish
ff
55
reports on us regularly, we could lose visibility in the financial markets, which in turnt
could cause our stock price or trading
volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our Class A common stock or
if our operating results do not meet their expectations, our stock price could decline.
Because we have elected to take advantage of the extended transition period pursuant to Section 107 of the JOBS Act,
our financial statements may not be comparable to those of other public companies.
Section 107 of the JOBS Act provides that an emerging growth company can use the extended transition period provided
in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This permits an emerging
growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private
companies. We are choosing to take advantage of this extended transition period and, as a result, we will comply with new or
revised accounting standards on the relevant dates on which adoption of such standards is required forff
private companies.
to companies that comply with public company effective dates,
Accordingly, our financial statements may not be comparablea
and our stockholders and potential investors may have difficulty in analyzing our operating results by comparing us to such
companies.
56
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information regarding our properties is contained in "Item 1—Business" and is incorporated by reference here.
Item 3. Legal Proceedings
Due to the naturet
of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims
related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against
us, if decided adversely, will have a material adverse effecff
t on our financial condition, cash flows or results of operations.
Item 4. Mine Safety Disclosures
Not applicable.
57
PART II
Item 5.
Securities
Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Common Stock
Our Class A common stock began trading on the NYSE under the symbol “MNRL” on April 18, 2019. Prior to that, there
was no public market for our Class A common stock.
There is no market for our Class B common stock. As of February 19, 2021, we had 48 holders of record of our Class B
common stock. Each share of Class B common stock has no economic rights but entitles its holders to one vote on all matters to
be voted on by the shareholders generally. Please see "Item 1—Business—Overview—Our Corporate Structure."
Holders of Record
On February 19, 2021, the closing price of our Class A common stock on the NYSE was $15.50 per share. As of
February 19, 2021, we had approximately 51 holders of record of our Class A common stock. This number excludes owners for
whom Class A common stock may be held in “street” name.
Dividend Policy
We paid our first quarterly cash dividend on our Class A common stock on August 29, 2019 to our Class A stockholders
and have continued to pay quarterly cash dividends to date. The amount of our dividend has varied quarter to quarter fromff
high of $0.38 per share to a low of $0.14 per share. We expect to pay futuret
amounts determined fromff
by us will be at the sole discretion of our board of directors, which may change our dividend policy at any time. Our board of
directors will take into account:
time to time by our board of directors. However, the declaration and payment of any future
dividends on our Class A common stock in
a
ff
dividends
•
•
•
•
•
•
general economic and business conditions;
our financial condition and operating results;
our free cash flow and current anticipated cash needs;
our capita
al requirements;
legal, tax, regulatory, and contractual (including under our revolving credit facff
payment of dividends by us to our stockholders or by our subsidiaries (including Brigham LLC) to us; and
ility) restrictions and implim cations on the
such other factors as our board of directors may deem relevant.
We are a holding company and have no material assets other than our ownership of Brigham LLC Units. As a
consequence, our ability to declare and pay dividends to the holders of our Class A common stock is subject to the ability of
Brigham LLC to provide distributions to us. If Brigham LLC makes such distributions, the Original Owners will be entitled to
receive equivalent distributions from Brigham LLC on a pro rata basis. However, because we must pay taxes, amounts
ultimately distributed as dividends to holders of our Class A common stock are expected to be less on a per share basis than the
amounts distributed by Brigham LLC to the Original Owners on a per unit basis.
Assuming Brigham LLC makes distributions to us and the Original Owners in any given year, we expect to pay dividends
in respect of our Class A common stock out of the portion, if any, of such distributions remaining after our payment of taxes
and our expenses (any such portion, an “excess distribution”). However, because our board of directors may determine to pay or
not pay dividends in respect of shares of our Class A common stock based on the factors described above, our holders of Class
A common stock may not necessarily receive dividend distributions relating to excess distributions, even if Brigham LLC
makes such distributions to us.
Securities Authorized for Issuance Under Equity Compensation Plans
58
The inforff mation relating to our equity compensation plans required by Item 5 is incorporated by reference to such
th in "Item 12—Security Ownership of Certain Beneficial Owners and Management and Related
information as set forff
Stockholder Matters” contained herein.
Issuer Purchases of Equity Securities
We did not purchase any shares of our common stock during
d
the three months ended December 31, 2020.
Performance Graph
The perforff mance graph below compares the cumulative total returns
of our Class A common stock over the period from
April 18, 2019, the date our Class A common stock began trading on the NYSE, through December 31, 2020 with the
for the same period for the S&P 500 index and S&P Oil and Gas Exploration & Production index. The
cumulative total returns
cumulative stockholder returnt
assumes that $100 was invested, including reinvestment of dividends, if any, in our Class A
common stock on April 18, 2019, and in the S&P 500 index and S&P Oil and Gas Exploration & Production index on the same
date.
t
t
PERFORMANCE GRAPH
Among Brigham Minerals, Inc., the S&P 500 Index, and the S&P Oil and Gas Exploration & Production
Index
e
u
l
a
V
t
n
e
m
t
s
e
v
n
I
$150
$125
$100
$75
$50
$25
04/18/19
4/19
6/19
9/19
12/19
03/20
06/20
09/20
12/20
Period Ending
Brigham Minerals, Inc.
S&P 500
S&P Oil and Gas Exploration & Production
***$100 invested on 4/18/19 in stock or 3/31/19 in index, including reinvestment of dividends. Fiscal year ending December 31.
The preceding performance graph and related information is being furnished pursuant to Item 2.01(e) of Regulation S-K
and shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C, other
than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act, except to the extent
that we specifically request that such information be treated as soliciting material or specifically incorporate it by reference into
a filff ing under the Securities Act or the Exchange Act.
Item 6.
Selected Financial Data
Brigham Minerals was formed in June 2018 and had limited historical finaff
ncial operating results prior to the IPO.
Following the IPO, Brigham Minerals became the sole managing member forff Brigham LLC. As a result, Brigham Minerals
consolidates the financial results of Brigham LLC and its subsidiaries and reports temporary equity related to the portion of the
Brigham LLC Units not owned by Brigham Minerals. For periods prior to the completion of the IPO, the accompanying
59
consolidated and combined finaff
ncial statements include the consolidated and combined historical financial results of Brigham
Resources (excluding the historical results of Brigham Operating), our predecessor for accounting purposes, and Brigham
Minerals.
The selected historical consolidated and combined finaff
ncial data as of and for the years ended December 31, 2020, 2019,
ncial statements included elsewhere in
2018, and 2017 were derived from the audited historical consolidated and combined finaff
this Annual Report. For a detailed discussion of the selected historical financ
, please
read "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations." The following tablea
ncial statements included elsewhere in this Annual Report. Among
should also be read in conjunction with our historical finaff
other things, the historical financial statements include more detailed informa
tion regarding the basis of presentation for the
information in the following tablea
. Historical results are not necessarily indicative of futuret
ial data contained in the following tablea
results.
ff
ff
(In thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
REVENUES
Mineral and royalty revenues
Lease bonus and other revenues
Total revenues
OTHER OPERATING INCOME:
Gain on sale of oil and gas properties, net
OPERATING EXPENSES
Gathering, transportation and marketing
Severance and ad valorem taxes
Depreciation, depletion, and amortization
Impairment of oil and gas properties
General and administrative
Total operating expenses
(LOSS) INCOME FROM OPERATIONS
Other income (expense):
(Loss) gain on derivative instruments, net
Interest expense, net
Loss on extinguishment of debt
Gain on sale and distribution of equity securities
Other income, net
(Loss) income before income tax expense
Income tax (benefit) expense
NET (LOSS) INCOME
Less: Net income attributable to Predecessor
Less: net loss (income) attributable to temporary
equity
Net (loss) income attributable to Brigham
Minerals, Inc. shareholders
Net income per share attributable to common
stockholders(1)
Basic
Diluted
Weighted-average number of shares
Basic
Diluted
$
$
$
$
$
$
$
$
$
Years Ended December 31,
2020
2019
2018
2017
86,245
5,478
91,723
$
$
97,886
3,629
101,515
$
$
59,758
7,506
67,264
$
$
30,066
10,842
40,908
—
—
—
94,551
6,985
5,606
48,238
79,569
21,619
162,017
$
(70,294) $
—
(890)
—
—
428
(70,756) $
(12,762)
(57,994) $
—
15,582
4,985
6,409
30,940
—
21,963
64,297
37,218
(568)
(5,609)
(6,892)
—
169
24,318
2,679
21,639
(5,092)
(9,646)
$
$
$
$
$
$
3,944
3,536
13,915
—
6,638
28,033
39,231
424
(7,446)
—
823
110
33,142
327
32,815
$
$
1,754
1,601
6,955
—
3,935
14,245
121,214
(121)
(556)
—
(4,222)
305
116,620
1,008
115,612
(30,976)
(115,612)
—
(42,412) $
6,901
$
1,839
$
(1.11) $
(1.11) $
0.26
0.26
$
$
38,178
38,178
22,870
22,870
— $
— $
—
—
—
—
—
—
—
—
(1)
Brigham Minerals was formed in June 2018 and acquired an interest in our predecessor as part of certain reorganization transactions in July 2018 and
increased its interest in our predecessor in April 2019 in connection with our IPO. To that end, we began recording net income attributable to
shareholders of Brigham Minerals in addition to net income attributable to our predecessor beginning in July 2018. Upon completion of the IPO, net
income attributable to our predecessor was reclassified as net income attributable to temporary equity.
60
(In thousands)
Other Financial Data:
Adjusted EBITDA(2)
Adjusted EBITDA ex lease bonus(2)
Balance Sheet Data:
Cash and cash equivalents
Total assets
Credit facilities
Total liabilities
Temporary equity
Permanent equity
Years Ended December 31,
2020
2019
2018
2017
$
$
$
$
$
$
$
$
65,042
59,564
9,144
680,961
20,000
29,031
146,280
505,650
$
$
$
$
$
$
$
$
78,207
74,578
51,133
784,162
$
$
$
$
— $
12,336
454,507
317,319
$
$
$
53,146
45,640
31,985
554,026
170,705
180,078
$
$
$
$
$
$
— $
33,618
22,776
6,886
334,477
27,000
32,303
—
373,948
$
302,174
(2)
Please read “—Non-GAAP Financial Measures” below for the definitions of Adjusted EBITDA and Adjusted EBITDA ex lease bonus and a
reconciliation of Adjusted EBITDA and Adjusted EBITDA ex lease bonus to our most directly comparable financial measure, calculated and presented
in accordance with accounting principles generally accepted in the United States of America ("GAAP").
Non-GAAP Financial Measures
Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus are non-GAAP supplemental financial
measures used by our management and by external users of our financial statements such as investors, research analysts and
others to assess the financial performance of our assets and their ability to sustain dividends over the long term without regard
to financing methods, capital structure or historical cost basis.
We define Adjud sted Net Income as net income (loss) before impairment of oil and gas properties, after tax, and loss on
extinguishment of debt, after tax. We define Adjud sted EBITDA as Adjuste
d Net Income before depreciation, depletion and
amortization, share based compensation expense, interest expense, gain or loss on derivative instruments and income tax
expense, less other income, gain on sale of oil and gas properties and income tax benefit.ff We define Adjusted EBITDA ex lease
bonus as Adjusted EBITDA furthe
r adjusted to eliminate the impacts of lease bonus revenue we receive due to the
t
unpredictability of timing and magnitude
of the revenue.
d
ff
Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus do not represent and should not be
considered alternatives to, or more meaningful than, net income, income from operations, cash flows from operating activities
or any other measure of financial perfoff rmance presented in accordance with GAAP as measures of our financial perforff mance.
Adjud sted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus have important limitations as analytical tools
because they exclude some but not all items that affect net income, the most directly comparable GAAP financial measure. Our
computations
computation of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus may differ fromff
of similarly titled measures of other companies.
61
(In thousands)
Reconciliation of Adjusted Net Income, Adjusted EBITDA and
Adjusted EBITDA ex lease bonus to net income:
Net (loss) income
Add:
Impairment of oil and gas properties, after tax (1)
Loss on extinguishment of debt, after tax (2)
Adjusted Net Income
Add:
Depreciation, depletion, and amortization
Share-based compensation expense
Interest expense, net
Loss on derivative instruments, net
Loss on sale and distribution of equity securities
Income tax expense
Less:
Gain on derivative instruments, net
Gain on sale of oil and gas properties
Other income, net
Gain on sale and distribution of equity securities
Adjusted EBITDA
Less:
Lease bonus revenue
Adjusted EBITDA ex lease bonus
(1) Tax effect of $14.4 million tax benefit for the year ended December 31, 2020.
(2) Tax effect of $0.8 million tax benefit for the year ended December 31, 2019.
Years Ended December 31,
2020
2019
2018
2017
$
(57,994) $
21,639
$
32,815
$
115,612
65,132
—
—
6,134
—
—
—
—
$
7,138
$
27,773
$
32,815
$
115,612
48,238
7,529
890
—
—
1,675
—
—
428
—
30,940
10,049
5,609
568
—
3,437
—
—
169
—
13,915
—
7,446
—
—
327
424
—
110
823
6,955
—
556
121
4,222
1,008
—
94,551
305
—
$
$
65,042
$
78,207
$
53,146
$
33,618
5,478
3,629
7,506
59,564
$
74,578
$
45,640
$
10,842
22,776
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysisyy
should be read in conjunction with “Item 6—Se
accompanying consolidated and combined finff ancial statements and related notes included elsewll
lected Financial Data” and the
here in this Aii
nnual Report.
66
e
tt
tt
ause or contribute
The forward-looking statements are dependent upon events,tt
The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefse
rr
ted performance.
and
may be outside
Our actual results could diffeff r materially from those discussed in these forward-looking statements. FacFF tors that
atural gas and NGLs,
conomic and
here in
Forward-Looking
onary Statement Regarding
of these risks, uncertainties and assumptions, the forward-looking
any forward-looking statements excepte
expec
x
our control.
could c
prices forff
ll
production volumes, estimates of proved, probable and possible reserves, mineral acquisiti
competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewll
this Aii
Statements,”tt
events dtt
rr
as otherwis
i
iscussed may not occur. We do not undertake akk
to such diffeff rences include, but are not limited to, marketkk
particularly in “Item 1A—Ris— k FactFF ors” and “CautiCC
all of which are diffiff cult to predict. In light
oil, nl
on capital, el
e required by applicable law.
nd uncertainties that
u
on to publicly ull
nnual Report,
i
ny obligati
risks akk
pdate
e
e
ii
tt
Overview
Brigham Minerals was formed to acquire and actively manage a portfolio of mineral and royalty interests in the core of
what we view as the most active, highly economic, liquids-rich resource plays across the continental United States. Our primary
business objective is to maximize risk-adjusted total returnt
to our shareholders through (i) the growth of our free cash floff w
generated from our existing portfolio of approximately 86,285 net royalty acres, and (ii) the continued sourcing and execution
of accretive mineral acquisitions in the core of highly economic, liquids-rich resource plays. As of December 31, 2020, we
owned 86,285 net royalty acres across 37 counties within the Permian Basin in West Texas and New Mexico, the SCOOP/
62
STACK plays in the Anadarko Basin of Oklahoma, the DJ Basin in Colorado and Wyoming and the Williston Basin in North
Dakota.
Financ
ii
ial and Operational Overview:
• Our production volumes increased 28%, to 9,483 Boe/d (72% liquids, 53% oil), for the year ended December 31, 2020
as compared to the prior year.
• Our mineral and royalty revenues composed of crude oil, natural
t
gas and NGL sales decreased 12%, to $86.2 million,
for the year ended December 31, 2020 as compared to the prior year.
• Our net loss for the year ended December 31, 2020 was $58.0 million. Adjusted Net Income was $7.1 million,
the twelve months
excluding an after-tax impairment to oil and gas properties of $65.1 million. Our net income forff
ended December 31, 2019 was $21.6 million, while Adjusted Net Income was $27.8 million. Adjusted EBITDA and
Adjusted EBITDA ex lease bonus decreased 17% to $65.0 million, and 20% to $59.6 million, respectively, for the
year ended December 31, 2020 as compared to the prior year. Adjusted Net Income, Adjusted EBITDA and Adjusted
EBITDA ex lease bonus are non-GAAP financial measures. For a definition of Adjusted Net Income, Adjusted
EBITDA and Adjusted EBITDA ex lease bonus and a reconciliation to our most directly comparablea
measure
calculated and presented in accordance with GAAP, please read "How We Evaluate Our Operations—Adjusted
EBITDA and Adjusted EBITDA Ex Lease Bonus."
• On February 19, 2021, the Board of Directors of Brigham Minerals declared a dividend of $0.26 per share of Class A
on March 26, 2021 to shareholders of record at the close of business on March 19, 2021.This
t
al returned
common stock payablea
brings the total capita
to shareholders related to financial results fromff
fiscal year 2020 to $1.01 per share.
• As of December 31, 2020, Brigham Minerals had a cash balance of $9.1 million and $115.0 million of capac
ility, providing the Company with total liquidity of $124.1 million.
revolving credit facff
a
ity on our
Market EnvirEE
onment and COVID-19
t
The ongoing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, has caused a
continuing disruption to the oil and natural
gas industry and to our business by, among other things, contributing to a significant
decrease in demand for crude oil and the price forff
oil beginning in the first quarter of 2020 and continuing through the fourth
led to agree to and maintain oil price and production
quarter of 2020. Additionally, in March 2020, Saudi Arabia and Russia faiff
controls within OPEC and Russia. Subsequently, Saudi Arabia announced plans to increase production and reduce the prices at
which they sell oil. While OPEC+ subsequently agreed to collectively decrease production, these events, combined with the
macro-economic impact of the continued outbreak of the COVID-19 pandemic and declining availability of hydrocarbon
storage, exacerbated the decline in commodity prices, including the historic, record low price of negative ($36.98) per barrel
that occurred in April 2020. Additionally, in July 2020, OPEC+ agreed to begin easing production cuts starting in August 2020.
Market volatility has continued, and we expect it will continue for the foreseeable future
. Please see “Item 1A—Risk Factors”
for further discussion of these events.
ff
In response to the COVID-19 pandemic, the potential risk to our workforce and in compliance with stay at home orders,
we successfully implemented policies and the technological infrastructuret
for all of our employees to work from home in the
first quarter of 2020 and ceased all business travel. In compliance with the requirements for the re-opening of the Texas
ity while continuing to support working from home for our
economy, we are currently operating our office at 75% capac
employees that are considered high-risk pursuant to the Centers forff Disease Control and Prevention guidelines or have
household members meeting the criteria of the guidelines. Due to these efforts, we have not experienced material disruptions to
our operations or the health of our workforce.
a
al expenditures forff
The declining commodity prices have adversely affected the revenues we receive for our royalty interests and could affect
al markets on terms favorable to us. Additionally, in response to the declining commodity prices,
our ability to access the capita
2020 and have announced similarly
al expenditures during
many operators on our properties substantially reduced their capita
reduced capita
2021 and beyond, which has adversely affected the development of our properties and will
continue to affect the development of our properties into 2021 and beyond. While these lower commodity prices initially
resulted in some of the Company's operators shutting in or curtailing production from wells on its properties during
the second
quarter of 2020, the Company saw a majority of its operators resume production for previously curtailed and shut in wells in
connection with the improvement of commodity prices in the third and fourth quarters of 2020. As a result of the shut-ins in the
second quarter of 2020 and the depressed commodity prices, our revenues, cash flows from operations and dividend amounts
d
d
63
we are able to pay our stockholders have continued to be negatively impacted. We cannot predict the extent and duration of
these and other impacts on our business fromff
the COVID-19 pandemic, efforts to fight
the pandemic and other market events.
ff
d
In connection with the previously mentioned COVID-19 pandemic and resulting market and commodity price challenges
experienced during
2020, we saw reduced levels of potential acquisition opportunities, which could potentially delay our ability
to execute on our growth strategy. With an improvement in commodity prices along with our financial strength, we are well
positioned to capture
al allocation is
within our control, we believe that the liquidity provided by our cash flow from operations and borrowings under our revolving
credit facility will provide us with sufficient capia tal to execute our current strategy.
attractive opportunities in 2021 that will generate shareholder value. Given that our capita
a
Operational Update
Mineral and Royalty Interest Ownership Update
During the year ended December 31, 2020, the Company completed 81 transactions acquiring 4,635 net royalty acres
rge, Williston and DJ Basins.
(standardized to a 1/8th royalty interest) for $66.5 million, in the Permian, SCOOP/STACK/MeKK
The Company deployed approximately 92% of its mineral acquisition capita
al in 2020 to the Permian Basin (70% Delaware and
22% Midland), 4% to the Anadarko Basin, 2% to the Williston Basin and 2% to the DJ Basin. The acquired minerals are
expected to deliver near-term production and cash flow growth with the addition of 165 gross DUCs (0.6 net DUCs) and 97
gross permits (0.3 net permits) to our inventory counts. As of December 31, 2020, the Company owned roughly 86,285 net
royalty acres, encompassing 13,496 gross (116.3 net) undeveloped horizontal locations, across 37 counties in what the
Company views as the core of the Permian Basin in West Texas and New Mexico, the SCOOP/STACK plays in the Anadarko
Basin of Oklahoma, the DJ Basin in Colorado and Wyoming and the Williston Basin in North Dakota.
The tablea
below summarizes the Company’s mineral and royalty interest ownership as of the dates indicated and changes
in such ownership on an annual basis.
Delaware Midland
SCOOP
STACK
DJ
Williston
Other
Total
28,330
27,550
26,550
26,550
25,750
2,580
5,220
4,875
4,800
4,575
4,100
1,120
—
10 %
—
27 %
11,400
11,400
11,375
11,375
11,100
300
—
10,725
10,725
10,700
10,700
10,700
25
—
15,890
15,600
15,600
15,600
15,600
290
—
7,950
7,825
7,825
7,825
7,750
200
—
6,770
6,725
6,725
6,650
7,200
120
(550)
3 %
— %
2 %
3 %
(6)%
86,285
84,700
83,575
83,275
82,200
4,635
(550)
5 %
Net Royalty Acres
December 31, 2020
September 30, 2020
June 30, 2020
March 31, 2020
December 31, 2019
Acres Added in 2020
Acres Sold in 2020
% Added in 2020
Operating Activity Update
DUC Conversions
In 2020, the Company identified approxi
70% of its gross DUC inventory (79% of its net DUCs) as of year-end 2019. 2020 conversions of gross wells by statust
summarized in the grapha
mately 628 gross DUCs (4.7 net DUCs) converted to production, representing
are
below:
a
6000
5250
4500
3750
3000
4908
424
628
41
16
5985
YE2019 PDP
Acquired Wells
Converted DUC
Converted
Permitted
Other
YE 2020 PDP
Drillii ingll
Activityii
64
During 2020 the Company saw 381 gross (2.6 net) wells spud on its acreage. 54% of gross (70% net) wells spud were in
the Permian Basin, with 35% gross (60% net) wells spud in the Delaware Basin and 19% gross (10% net) wells spud in the
Midland Basin:
Gross Spuds
Net Spuds
400
350
300
250
200
150
100
50
0
24848
2302300
214
2099
18585
208
150
99
82822
2
1.75
1.5
1.25
1
0.75
5757
363636
7979
0.5
0.25
0
1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20
Delaware
DJ Basin
Midland
Williston
SCOOP
Other
STACK
Net Spuds
DUC and Permit Iii nvII
yr
entortt
The Company expects any near-term production growth will be driven by the continued conversion of its DUC and
permit inventory. Brigham’s DUC and permit inventory as of December 31, 2020 by basin is outlined in the tabla e below:
Gross Inventory
DUCs
Permits
Net Inventory
DUCs
Permits
Delaware Midland
SCOOP
STACK
DJ
Williston
Other
Total
Development Inventory by Basin (1)
187
159
1.8
0.9
218
97
0.7
0.4
62
11
0.3
—
3
6
—
—
111
222
0.7
2.2
124
252
0.1
0.5
16
8
0.1
0.1
721
755
3.6
4.2
(1) Individual amounts may not total due to rounding.
We use a variety of operational and financial measures to assess our performance. Among the measures considered by
management are the following:
How We Evaluate Our Operations
•
•
•
volumes of oil, natural
t
gas and NGLs produced;
number of rigs on location, permits, spuds, completions and wells turned-in-line;
commodity prices; and
• Adjusted EBITDA and Adjusted EBITDA ex lease bonus.
65
Volumes of Oil, Natural Gas and NGLs Produced
In order to track and assess the performanc
e of our assets, we monitor and analyze our production volumes from the
various resource plays that comprise our portfolio of mineral and royalty interests. We also regularly compare projected
volumes to actual reported volumes and investigate unexpected variances.
ff
Number of Rigs on Location, Permits, Spuds, Completions and Wells Turned-In-Line
In order to track and assess the perfoff rmance of our assets, we monitor and analyze the number of rigs currently drilling
our properties. We also constantly monitor the number of permits, spuds, completions and wells on production that are
applicable to our mineral and royalty interests in an effort to evaluate near-term production growth from the various basins and
resource plays that comprise our asset base.
Commodity Prices
t
Historically, oil, natural
gas and NGL prices have been volatile and may continue to be volatile in the future. During the
past five years, the posted price forff WTI has ranged from a historic, record low price of negative ($36.98) per barrel in April
2020 to a high of $77.41 per barrel in June 2018. The Henry Hrr
gas has ranged from a low
of $1.33 per MMBtu in September 2020 to a high of $6.24 per MMBtu in January 2018. As of December 31, 2020, the posted
gas was $2.36 per MMBtu. Lower prices
price forff
t
gas and NGLs that our operators can produce
may not only decrease our revenues, but also potentially the amount of oil, natural
economically.
oil was $48.35 per barrel and the Henry Hrr
ub spot market price of natural
ub spot market price forff
t
natural
t
The prices we receive for oil, natural
al area. The relative prices of these products are
a
tors affecting global and regional supply and demand dynamics, such as economic and geopolitical
determined by facff
conditions, production levels, availability of transportation, weather cycles and other facff
tors. In addition, realized prices are
influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and
NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States.
gas and NGLs vary by geographic
t
Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many
factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic
oil pricing index. The majora
ity of our oil production is priced at the prevailing market price with the final realized price affected
by both quality and location differentials.
The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products.
As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price
adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality
differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities,
such as sulfur.
Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and
refining markets and majoa r trading points.
Natural Gas. The NYMEX price quoted at Henry Hub iu
United States. The actual volumetric prices realized fromff
result of quality and location differentials.
the sale of natural
t
gas differ fromff
s a widely used benchmark for the pricing of natural
gas in the
t
the quoted NYMEX price as a
Quality differentials result from the heating value of natural
t
r
hydrogen sulfide, carbon
and will realize a higher volumetric price than natural
gas with a higher concentration of impurities will realize a lower volumetric price dued
natural gas when sold or the cost of treating the naturat
t
gas measured in Btus and the presence of impurities, such as
alue
gas that is predominantly methane, which has a lower Btu value. Natural
to the presence of the impurities in the
dioxide and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu vt
l gas to meet pipeline quality specificff ations.
Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply
and demand conditions and the cost to transport natural gas to end-user markets.
NGLs.GG
NGL pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.
Oil and Gas Properties
66
t
alized costs of oil and natural
Under the full cost method of accounting, total capita
gas properties, net of accumulated
depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues fromff
proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated properties, less related income tax
s (full cost ceiling limitation). A write-down of the carryirr ng value of the full cost pool ("impairment charge") is a noncash
ff
effect
charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower depletion expense in
future periods. A ceiling limitation is calculated at each reporting period. The ceiling limitation calculation is prepared using an
unweighted arithmetic average of oil prices ("SEC oil price") and natural
gas prices ("SEC gas price") as of the first day of each
t
the trailing 12-month period ended, as required under the guidelines established by the SEC. As of December 31,
month forff
2020, 2019 and 2018, the SEC oil prices were $39.57, $55.65, and $65.66, respectively, per barrel forff
oil, adjusted by area forff
energy content, transportation fees and regional price differentials, and the SEC gas prices were $2.00, $2.60, and $3.12,
respectively, per MMBtu for natural
transportation fees and regional price
differentials. As a result of the decline in the SEC oil prices and the SEC gas prices during the twelve months ended
December 31, 2020, and taking into consideration certain reclassifications of proved undeveloped reserves to probable and
possible reserves during the three months ended December 31, 2020, as a result of a slowdown in operator activity, the net book
value of oil and natural
gas properties exceeded the ceiling limitation, as of September 30, 2020 and December 31, 2020,
resulting in an impairment charge of $79.6 million to oil and gas properties, net during the year ended December 31, 2020.
There were no impairment charges during
the years ended December 31, 2019 and 2018.
gas, adjusted by area forff
energy content,
d
t
t
Further declines in the SEC oil price or the SEC gas price could lead to additional impairment charges in the future and
such impairment charges could be material. In addition to the impact of lower prices, any future changes to assumptim ons of
of oil and gas properties, proved undeveloped
drilling and completion activity, development timing, acquisitions or divestitures
locations, and production and other estimates may require revisions to estimates of total proved reserves which would impact
the amount of any impairment charge. Based on specific market factors and circumstances at the time of prospective
impairment reviews, and the continuing evaluation of development activities, production data, economics and other facff
tors, we
periods. The risk that we will be required to
may be required to write down the carrying value of our properties in future
recognize impairments of our oil, natural
gas and NGL properties increases during sustained periods of low commodity prices.
In addition, impairments could occur if we were to experience sufficient downward adjustments to our estimated proved
reserves or the present value of estimated future
net revenues. If we incur impairment charges in the future, our results of
operations for the periods in which such charges are taken may be materially and adversely affected.
ff
ff
t
t
Hedging
We may enter into certain derivative instruments to partially mitigate the impact of commodity price volatility on our
cash flow generated from operations. From time to time, such instruments may include variable-to-fixed-price swapsa , fixff ed-
price contracts, costless collars and other contractual arrangements. The impact of these derivative instruments could affect the
amount of cash flows we ultimately realize. Historically, we have only entered into minimal fixed-price swap ca
ontracts. Under
fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike
price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike
d-price swap contracts in the future to mitigate the impact of
price. We may employ contractual arrangements other than fixeff
price flucff
of lower
prices on our future revenue.
tuations. If commodity prices decline in the future, our hedging contracts may partially mitigate the effect
ff
Our revolving credit facility allows us to hedge up to 85% of our reasonably anticipated projected production from our
proved reserves of oil and natural
gas
or oil derivative contracts in place as of December 31, 2020 and 2019. For the years ended December 31, 2019 and 2018, we
recorded a loss on commodity derivative instruments, net of $0.6 million and a gain of $0.4 million, respectively. See “Note 5
ncial statements of Brigham Minerals included elsewhere in
—Derivative Instruments” to the consolidated and combined finaff
this Annual Report.
o 60 months in the future. We did not have any natural
gas, calculated separately, for up tu
t
t
Adjusted EBITDA and Adjusted EBITDA Ex Lease Bonus
ncial
Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus are non-GAAP supplemental finaff
measures used by our management and by external users of our financial statements such as investors, research analysts and
others to assess the financial performance of our assets and their ability to sustain dividends over the long term without regard
to financing methods, capita
al structure or historical cost basis.
We defineff
Adjusted Net Income as net income (loss) before impairment of oil and gas properties, after tax, and loss on
extinguishment of debt, after tax. We define Adjusted EBITDA as Adjusted Net Income beforff e depreciation, depletion and
amortization, share based compensation expense, interest expense, gain or loss on derivative instruments and income tax
67
expense, less other income, gain on sale of oil and gas properties and income tax benefit.ff We define Adjusted EBITDA ex lease
bonus as Adjusted EBITDA furthe
r adjusted to eliminate the impacts of lease bonus revenue we receive due to the
t
unpredictability of timing and magnitude
of the revenue.
ff
Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus do not represent and should not be
considered alternatives to, or more meaningful than, net income, income from operations, cash flows fromff
operating activities
or any other measure of financial perfoff rmance presented in accordance with GAAP as measures of our financial perforff mance.
Adjud sted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus have important limitations as analytical tools
because they exclude some but not all items that affect net income, the most directly comparable GAAP financial measure. Our
computations
computation of Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA ex lease bonus may differ fromff
of similarly titled measures of other companies. For further discussion, please read “Item 6—Selected Financial Data—Naa
on-
GAAP Financial Measures.”
Sources of Our Revenues
t
Our revenues are primarily derived from the mineral and royalty payments we receive froff m our operators based on the
lease bonus payments. Mineral and royalty
our properties, as well as fromff
sale of oil, natural
revenues may vary s
ignificantly from period to period as a result of changes in volumes of production sold by our operators,
rr
production mix and commodity prices. Lease bonus revenues vary from period to period as a result of leasing activity on our
mineral interests.
gas and NGLs produced fromff
The following tablea
presents the breakdown of our revenues forff
the following periods:
Revenue
Mineral and royalty revenues
Oil sales
Natural gas sales
NGL sales
Total mineral and royalty revenues
Lease bonus revenue
Total revenue
Years Ended December 31,
2020
2019
2018
74 %
11 %
9 %
94 %
6 %
100 %
81 %
9 %
6 %
96 %
4 %
100 %
70 %
11 %
8 %
89 %
11 %
100 %
Principle Components of Our Cost Structure
The following is a description of the principle components of our cost structure.
However, as an owner of mineral and
al expenditures to bring a horizontal well on line,
royalty interests, we are not obligated to fund drilling and completion capita
lease operating expenses to produce our oil, natural
gas and NGLs nor the plugging and abandonment costs at the end of a
well’s economic life.ff All the aforementioned costs are borne entirely by the exploration and production companies that have
leased our mineral and royalty interests.
t
t
Gathering, Transportation and Marketing Expenses
Gathering, transportation and marketing expenses include the costs to process and transport our production to applicable
sales points. Generally, the terms of the lease governing the development of our properties permits the operator to pass through
these expenses to us by deducting a pro rata portion of such expenses from our production revenues.
Severance and Ad Valorem Taxes
t
Severance taxes are paid on produced oil, natural
gas or NGLs based on either a percentage of revenues from production
sold or the number of units of production sold at fixed rates established by federal, state or local taxing authorities. In general,
the production taxes we pay correlate to changes in our oil, natural
gas and NGL revenues, which is driven by our production
t
gas and NGLs. We are also subject to ad valorem taxes in some of the counties
volumes and prices received for our oil, natural
where our production is located. Ad valorem taxes are generally based on the state or local government’s appraisal of the value
gas and NGL
of our oil, natural
prices. Rates, methods of calculating property values and timing of payments vary across the different
counties in which we
own mineral and royalty interests.
gas and NGL properties, which also trend with anticipated production, as well as oil, natural
ff
t
t
t
68
Depreciation, Depletion and Amortization
t
Depreciation, depletion and amortization (“DD&A”) is the systematic expensing of the capita
alized costs incurred to
gas properties. We use the full cost method of accounting, and, as such, all acquisition-related
acquire evaluated oil and natural
costs to acquire evaluated properties are capita
alized and amortized in aggregate based on the estimated economic productive
lives of our properties. Depletion is the expense recorded based on the cost basis of our properties and the volume of
hydrocarbons extracted during
each respective period, calculated on a units-of-production basis. Estimates of proved reserves
are a major component of our calculation of depletion. We adjust our depletion rates quarterly based upon the quarter-end
internally generated reserve reports unless circumstances indicate that there has been a significant change in reserves or costs.
The year-end reserve reports are audited by CG&A.
d
General and Administrative
s forff
General and administrative (“G&A”) expenses are costs incurred forff
our
staff, share-based compensation expense, costs of maintaining our headquarters, costs of managing our properties, audit and
other feeff
professional services and legal compliance. As a result of becoming a public company, we incurred incremental
G&A expenses including, but not limited to, costs associated with hiring new personnel, implementation of compensation
programs that are competitive with our public company peer group including share-based compensation, annual and quarterly
reports to stockholders, tax returnt
preparation, independent and internal auditor fees, investor relations activities, registrar and
transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These
incremental G&A expenses are not reflected in our historical finff ancial statements before the IPO date.
overhead, including payroll and benefits forff
Interest Expense
We finance a portion of our working capita
al requirements and acquisitions with borrowings under our revolving credit
facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.
We reflect interest paid to the lenders under our debt arrangements (currr ently, our revolving credit facility) in interest expense.
In connection with the closing of our IPO, we fully repaid the outstanding borrowings under our Owl Rock credit facility.
ncial statements of Brigham Minerals included
Please see “Note 7—Long-Term Debt” to the consolidated and combined finaff
elsewhere in this Annual Report.
Income Tax Expense
hise tax
Brigham Minerals is subject to U.S. federal and state income taxes as a corporation. Texas imposes a franc
(commonly referred to as the Texas margin tax) at a rate of up to 1.00% on gross revenues less certain deductions, as
specifically set forth in the Texas margin tax statutet
. A portion of our mineral and royalty interests are located in Texas basins.
Our predecessor was treated as a flowff
-through entity, and is currently treated as a disregarded entity, for U.S. federal income
tax purposes and, as such, is generally not subject to U.S. federal income tax at the entity level.
ff
69
Year Ended December 31, 2020 Compared to Ytt
earYY
Ended December 31, 2019
Results of Operations
The following tablea
provides the components of our revenues and expenses forff
the periods indicated, as well as each
period’s respective average prices and production volumes:
(dollars in thousands, except forff
Production
realized prices)
Oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Equivalents (MBoe)
Equivalents per day (Boe/d)
Revenues
Oil sales
Natural gas sales
NGL sales
Total mineral and royalty revenues
Lease bonus and other revenue
Total revenue
Realized prices, without derivatives:
Oil ($/Bbl)
Natural gas ($/Mcf)
NGLs ($/Bbl)
Equivalents ($/Boe)
Realized prices, with derivatives(1):
Oil ($/Bbl)
Equivalents ($/Boe)
Operating expenses
Gathering, transportation and marketing
Severance and ad valorem taxes
Depreciation, depletion, and amortization
Impairment of oil and gas properties
General and administrative (before share-based compensation)
Total operating expenses (before share-based compensation)
Share-based compensation
Total operating expenses
Other income (expense)
(Loss) gain on derivative instruments, net
Loss on extinguishment of debt
Interest expense, net
Total other income (expense), net
Unit Expenses ($/Boe)
Gathering, transportation and marketing
Severance and ad valorem taxes
Depreciation, depletion, and amortization
General and administrative (before share-based compensation)
Share-based compensation expense
Interest expense, net
70
Year Ended December 31,
2020
2019
Variance
1,823
5,809
680
3,471
9,483
67,909
10,443
7,893
86,245
5,478
91,723
37.26
1.80
11.61
24.85
37.26
24.85
$
$
$
$
$
1,515
4,707
407
2,706
7,414
82,048
9,724
6,114
97,886
3,629
101,515
54.16
2.07
15.03
36.17
54.47
36.35
308
1,102
273
765
2,069
(14,139)
719
1,779
(11,641)
1,849
(9,792)
(16.90)
(0.27)
(3.42)
(11.32)
(17.21)
(11.50)
$
$
$
$
$
6,985
$
4,985
$
2,000
5,606
48,238
79,569
14,090
154,488
7,529
162,017
$
$
6,409
30,940
—
11,914
54,248
10,049
(803)
17,298
79,569
2,176
$ 100,240
(2,520)
64,297
$
97,720
— $
(568) $
—
(890)
(6,892)
(5,609)
568
6,892
4,719
(890) $
(13,069) $
12,179
$
2.01
1.62
13.90
4.06
2.17
0.26
$
1.84
2.37
11.43
4.40
3.71
2.07
0.17
(0.75)
2.47
(0.34)
(1.54)
(1.81)
$
$
$
$
$
$
$
$
$
$
$
20 %
23 %
67 %
28 %
28 %
(17)%
7 %
29 %
(12)%
51 %
(10)%
(31)%
(13)%
(23)%
(31)%
(32)%
(32)%
40 %
(13)%
56 %
***
18 %
185 %
(25)%
152 %
(100)%
(100)%
(84)%
(93)%
9 %
(32)%
22 %
(8)%
(42)%
(87)%
(1) Hedge prices reflect the effect
gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.
*** A percentage calculation is not meaningful due to change in signs, zero-value denominator or a change greater than 300.
of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized
ff
Revenues
Total revenues for the year ended December 31, 2020 decreased by 10%, or $9.8 million, compared to the year ended
to a $11.6 million decrease in mineral and royalty revenues during the
December 31, 2019. The decrease was attributablea
period, partially offset by a $1.8 million increase in lease bonus revenue. The decrease in mineral and royalty revenues was
primarily the result of a decrease in realized commodity prices of 31% resulting in a $39.3 million decrease in mineral and
royalty revenues. This was partially offset by an increase in drilling and completion activity on our mineral and royalty
interests, and to a lesser degree by acquisitions of proved developed producing reserves, which resulted in a 28% increase in
production volumes to 9,483 Boe/d and a corresponding increase in mineral and royalty revenues of $27.7 million.
Oil revenues for the year ended December 31, 2020 decreased by 17%, or $14.1 million, compared to the year ended
to the 31% decrease in realized oil price to $37.26
December 31, 2019. The decrease in oil revenues was primarily attributablea
per barrel resulting in a decrease in revenue of $30.8 million. This was partially offset by a 20% increase in oil production
volumes to 4,980 barrels per day resulting in a $16.7 million increase in oil revenues. The increase in oil production volumes
for the period was primarily attributablea
to increased drilling and completion activity on our properties in the Permian Basin.
Natural gas revenues for the year ended December 31, 2020 increased by 7%, or $0.7 million compared to the year ended
gas
gas
to increased drilling and completion activity on our properties in
gas price to $1.80 per Mcf resulting in a
December 31, 2019. The increase in natural
t
production volume to 15,871 Mcf/d resulting in a $2.3 million increase in natural
production volumes for the period was primarily attributablea
the Permian Basin. This was partially offset by a 13% decrease in realized natural
decrease in revenue of $1.6 million.
to the 23% increase in natural
gas sales. The increase in natural
gas revenues was primarily attributablea
t
t
t
t
NGL revenues for the year ended December 31, 2020 increased by 29%, or $1.8 million compared to the year ended
to the 67% increase in NGL volumes to 1,858
December 31, 2019. The increase in NGL revenues was primarily attributablea
Boe/d resulting in a $4.1 million increase in NGL sales was primarily attributablea
to increased drilling and completion activities
on our properties in the Permian Basin. This was partially offset by a 23% decrease in NGL prices to $11.61 per barrel
resulting in a decrease in revenue of $2.3 million.
Lease bonus revenues forff
December 31, 2019. The increase was primarily attributablea
offset by a decrease in leasing activity in Colorado and Oklahoma. Other revenues include payments forff
surface damages and were not a significant portion of the overall amount.
the year ended December 31, 2020 increased by 51%, or $1.8 million compared to the year ended
to an increase in leasing activity on our interests in Texas, partially
right-of-way and
Operatingtt
tt
and other
s
expense
xx
Gathering, transportation, and marketing expenses for the year ended December 31, 2020 increased by 40%, or $2.0
million, as compared to the year ended December 31, 2019, which was largely driven by the 28% increase in our production
volumes as well as an increase in gathering, transportation and marketing rates.
Severance and ad valorem taxes for the year ended December 31, 2020 decreased by 13%, or $0.8 million, as compared to
the year ended December 31, 2019, primarily due to the 12% decrease in mineral and royalty revenues.
DD&A expense for the year ended December 31, 2020 increased by 56%, or $17.3 million, compared to the year ended
December 31, 2019, which was primarily due to an increase in depletion expense of $17.0 million. Higher production volumes
increased our depletion expense by $8.6 million, and a higher depletion rate increased our depletion expense by $8.4 million.
The depletion rate was $13.63 per Boe and $11.22 per Boe for the years ended December 31, 2020 and 2019, respectively. The
on largely de-risked acreage with an increased
increase in the depletion rate was a result of recent acquisition efforts focused
likelihood of near-term production and development, as well as reclassificatio
n of proved undeveloped reserves to probable and
possible reserves due to changes in assumptim ons of the development timing as a result of reduced activity by our operators. We
adjust our depletion rates quarterly based upon the quarter-end internally generated reserve reports.
ff
ff
As of September 30, 2020 and December 31, 2020, the net capia talized costs of our oil and gas properties exceeded the full
cost ceiling limitation primarily due to the decline in oil and gas prices and reclassification of proved undeveloped reserves to
probable and possible reserves during the three months ended December 31, 2020 as a result of a slowdown in operator activity.
As a result, we recorded impairments of our oil and gas properties, net of $79.6 million for the year ended December 31, 2020.
71
In determining the full cost ceiling impairment at December 31, 2020, we estimated the PV-10 of our total proved oil and
natural
gas reserves using the SEC oil price and the SEC gas price of $39.57 per Bbl and $2.00 per MMBtu, respectively, which
t
is a decrease of 29% and 23%, respectively, from the December 31, 2019 SEC oil price and SEC gas price of $55.65 per Bbl
and $2.60 per MMBtu, respectively. No impaim rment charge was recorded forff
the year ended December 31, 2019.
G&A for the year ended December 31, 2020 increased by 18%, or $2.2 million, compared to the year ended December 31,
2019. Increases to G&A expense are a result of: (i) $0.7 million in incremental legal, professional, audit, and tax feeff
s as a
result of the Company's June 2020 Secondary Offering and September 2020 Secondary Offering, (ii) $0.5 million in additional
rent expense, (iii) $0.4 million of incremental directors and officers insurance expenses, and (iv) $0.3 million of additional
salaries dued
to an increase in headcount.
Share-based compensation expense for the year ended December 31, 2020 decreased by 25%, or $2.5 million compared to
to a cumulative effect
the year ended December 31, 2019. The decrease in share-based compensation expense was dued
adjustment of $5.2 million pertaining to the period from the grant date to the IPO, which consists of a $2.0 million cumulative
effect adjustment related to the estimated fair value of the Incentive Units and a $3.2 million cumulative effect adjustment
related to the estimated fair value of the RSAs, partially offset by share-based compensation expense related to awards granted
alizes a portion of the share-based compensation cost
during the year ended December 31, 2020. Brigham Minerals capita
incurred after the IPO. See tablea
ncial
statements of Brigham Minerals included elsewhere in this Annual Report for further discussion.
below and "Note 10—Share-Based Compensation" to the consolidated and combined finaff
(In thousands)
Incentive Units
RSAs
RSUs
PSUs
Capitalized share-based compensation
Total share-based compensation expense
Years Ended December 31,
2020
2019
Variance
$
712
$
2,904
$
1,254
7,390
4,259
3,972
4,630
2,361
(6,086)
(3,818)
$
7,529
$
10,049
$
(2,192)
(2,718)
2,760
1,898
(2,268)
(2,520)
Interest expense, net for the year ended December 31, 2020 decreased by 84%, or $4.7 million, compared to the year ended
December 31, 2019 due to lower average outstanding borrowings and lower average interest rates. For the year ended
December 31, 2020, our weighted average debt outstanding on our revolving credit facility was $2.8 million compared to our
weighted average debt outstanding on our Owl Rock credit facility and revolving credit facility combined of $55.0 million for
the year ended December 31, 2019. Our weighted average interest was 1.91% and 7.29% for the years ended December 31,
2020 and 2019, respectively. In May 2019, a portion of the net proceeds received from the IPO were used to fully repay the
outstanding borrowings under the Owl Rock credit facility. In December 2019, a portion of the net proceeds received from the
December 2019 Offering were used to fully repay the outstanding borrowings under our revolving credit facility. See table
below and “Note 7—Long-Term Debt” and “Note 1—Business and Basis of Presentation” to the consolidated and combined
financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion of this transaction.
(In thousands, except for interest rate)
Interest expense - Owl Rock credit facility
ff
Interest expense - Revolving Credit facility
Commitment fees
Amortization of loan closing costs
Interest income
Total interest expense, net
Years Ended December 31,
2020
2019
Variance
— $
5,238
$
$
$
55
600
605
(370)
890
590
356
433
(1,008)
(5,238)
(535)
244
172
638
$
5,609
$
(4,719)
Total weighted average interest rate
1.91 %
7.29 %
Total weighted average debt balance
$
2,814
$
55,000
Loss on extinguishment of debt. As a result of the full repayment of the outstanding balance of the Owl Rock credit
facility of $200.0 million in May 2019, we recognized a loss on extinguishment of debt of approximately $6.9 million for the
72
year ended December 31, 2019. The loss on extinguishment of debt consisted of a $4.0 million write-off of capita
alized debt
issuance costs, a $2.1 million prepayment fee and legal fees of $0.8 million. See “Note 7—Long-Term Debt” to the
consolidated and combined finaff
ncial statements of Brigham Minerals included elsewhere in this Annual Report for further
discussion of these transactions.
Loss on derivative instruments, net. Brigham Minerals did not have any derivative contracts in place as of December 31,
s index. For the
2020 and 2019. Prior to December 31, 2019, we had certain oil swap contracts based on the NYMEX future
to oil
year ended December 31, 2019, we recognized a loss on derivative instruments, net of $0.6 million, which is attributablea
derivative instruments. We realized $0.5 million of gains on our settled derivative instruments during the year ended
December 31, 2019. See “Note 5—Derivative Instruments” to the consolidated and combined finaff
ncial statements of Brigham
Minerals included elsewhere in this Annual Report for further discussion of these transactions.
ff
73
Year EndEE eddd December 31, 2019 Comparem
d to Ytt
earYY
Ended December 31, 2018
The following tablea
provides the components of our revenues and expenses forff
the periods indicated, as well as each
period’s respective average prices and production volumes:
(dollars in thousands, except forff
Production
realized prices)
Oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Equivalents (MBoe)
Equivalents per day (Boe/d)
Revenues
Oil sales
Natural gas sales
NGL sales
Total mineral and royalty revenues
Lease bonus and other revenues
Total revenue
Realized prices, without derivatives:
Oil ($/Bbl)
Natural gas ($/Mcf)
NGLs ($/Bbl)
Equivalents ($/Boe)
Realized prices, with derivatives(1):
Oil ($/Bbl)
Equivalents ($/Boe)
Operating expenses
Gathering, transportation and marketing
Severance and ad valorem taxes
Depreciation, depletion, and amortization
General and administrative (before share-based compensation)
Year Ended December 31,
2019
2018
Variance
1,515
4,707
407
2,706
7,414
777
2,507
222
1,417
3,881
738
2,200
185
1,289
3,533
$
82,048
$
47,040
$
35,008
7,014
5,704
59,758
7,506
67,264
60.56
2.80
25.72
42.19
59.59
41.66
$
$
$
$
$
$
$
$
$
$
9,724
6,114
97,886
3,629
$
$ 101,515
54.16
2.07
15.03
36.17
54.47
36.35
$
$
$
$
4,985
$
3,944
$
6,409
30,940
11,914
3,536
13,915
6,638
95 %
88 %
83 %
91 %
91 %
74 %
39 %
7 %
64 %
(52)%
51 %
(11)%
(26)%
(42)%
(14)%
(9)%
(13)%
26 %
81 %
122 %
79 %
94 %
***
129 %
(234)%
***
(25)%
86 %
2,710
410
38,128
(3,877)
34,251
(6.40)
(0.73)
(10.69)
(6.02)
(5.12)
(5.31)
1,041
2,873
17,025
5,276
26,215
10,049
36,264
(992)
(6,892)
1,837
(6,047)
Total operating expenses (before share-based compensation)
$
54,248
$
28,033
$
Share-based compensation
Total operating expenses
Other income (expense)
10,049
64,297
—
28,033
(Loss) gain on derivative instruments, net
$
(568) $
424
$
Loss on extinguishment of debt
Interest expense, net
Total other income (expense), net
(6,892)
(5,609)
(13,069)
—
(7,446)
(7,022)
Hedged prices reflect the effect
(1)
gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.
*** A percentage calculation is not meaningful due to change in signs, zero-value denominator or a change greater than 300.
of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized
ff
Revenues
Total revenues for the twelve months ended December 31, 2019 increased by 51%, or $34.2 million, compared to the
year ended December 31, 2018. The increase was attributable to a $38.1 million increase in mineral and royalty revenues during
the period, partially offset by a $3.9 million decrease in lease bonus revenue. The increase in mineral and royalty revenues was
primarily the result of increased drilling and completion activity on our mineral and royalty interests, which resulted in a 91%
increase in production volumes to 7,414 Boe/d and a corresponding increase in revenue of $54.4 million. Realized commodity
prices decreased 14% resulting in an additional $16.3 million decrease in mineral and royalty revenues.
d
74
Oil revenues for the year ended December 31, 2019 increased by 74%, or $35.0 million, compared to the year ended
December 31, 2018. Oil production volumes increased 95% to 4,151 barrels per day resulting in a $44.7 million increase in oil
revenues. The increase in oil production volumes for the period was primarily attributablea
to increased drilling and completion
activity on our properties in Texas, Oklahoma, North Dakota and New Mexico. Realized oil prices decreased 11% to $54.16 per
barrel resulting in a decrease in revenue of $9.7 million.
Natural gas revenues for the year ended December 31, 2019 increased by 39%, or $2.7 million compared to the year
ended December 31, 2018. Natural gas production volumes increased 88% to 12,896 Mcf/d resulting in a $6.1 million increase
to increased
t
in natural
drilling and completion activity on our properties in Oklahoma, Colorado, North Dakota, Texas and New Mexico. Realized
t
natural
gas prices decreased by 26% to $2.07 per Mcf resulting in a decrease in revenue of $3.4 million.
gas production volumes for the period was primarily attributablea
gas sales. The increase in natural
t
NGL revenues for the year ended December 31, 2019 increased by 7%, or $0.4 million compared to the year ended
December 31, 2018. NGL production volumes increased by 83% to 1,114 Boe/d resulting in a $4.8 million increase in NGL
sales, while realized NGL prices decreased by 42% to $15.03 per barrel resulting in a decrease in revenue of $4.4 million.
Lease bonus revenue for the year ended December 31, 2019 decreased by 52%, or $3.9 million, compared to the year
to a decrease in leasing activity on our interests in
right-of-way and
ended December 31, 2018. The decrease was primarily attributablea
Oklahoma, partially offset by an increase in leasing activity in Texas. Other revenues include payments forff
surface damages and were not a significant portion of the overall amount.
Operatingtt
tt
and other
s
expense
xx
Gathering, transportation and marketing expenses for the year ended December 31, 2019 increased by 26%, or $1.0
million, as compared to the year ended December 31, 2018, which was largely driven by the increase in our production
volumes, partially offset by lower gathering, transportation and marketing rates.
Severance and ad valorem taxes for the year ended December 31, 2019 increased by 81%, or $2.9 million, as compared to
the year ended December 31, 2018, which was primarily due to higher severance taxes associated with oil revenue as a result of
higher oil production volumes and higher oil prices, as well as higher ad valorem taxes in Texas.
DD&A expense for the year ended December 31, 2019 increased by 122%, or $17.0 million, compared to the year ended
December 31, 2018, which was primarily due to an increase in depletion expense of $17.1 million. Higher production volumes
increased our depletion expense by $12.1 million, and a higher depletion rate increased our depletion expense by $5.0 million.
General and administrative expense (before share-based compensation expense) for the year ended December 31, 2019
increased by 79%, or $5.3 million, compared to the year ended December 31, 2018. Increases to G&A expense are a result of:
(i) $0.7 million of incremental audit and tax feeff
to increase in headcount, (iii) $1.1
million of incremental D&O insurance expenses, (iv) $1.1 million of legal and professional fees and (v) $1.7 million of other
incremental expenses as a result of becoming a publicly traded company.
s, (ii) $0.7 million of additional salaries dued
Share-based compensation expense for the year ended December 31, 2019 was $10.0 million net of $3.8 million of share-
alized to unevaluated property. At IPO, we recognized a cumulative effect adjustment of $2.0
based compensation cost capita
million of share-based compensation cost related to the Incentive Units, pertaining to the period from the grant date through the
IPO. Additionally, in April of 2019, in connection with the IPO, we adopted the Brigham Minerals, Inc. 2019 LTIP and granted
restricted stock awards ("RSAs"), restricted stock units ("RSUs") and performance-based vesting units ("PSUs") to our
employees and executives. Certain of the RSAs vested immediately and we recognized $3.2 million of share-based
compensation cost related to the RSAs. Also, subsequent to the IPO and prior to December 31, 2019, we recognized an
additional $8.6 million of share-based compensation cost related to the Incentive Units and the awards granted under the LTIP.
No share-based compensation expenses were recognized prior to the IPO because the IPO was not considered probable. See
ncial statements of Brigham Minerals, Inc. as of
“Note 10—Share-Based Compensation” to the consolidated and combined finaff
December 31, 2019 included elsewhere in this Annual Report for further discussion.
Interest expense for the year ended December 31, 2019 decreased by $1.8 million, compared to the year ended December
31, 2018 due to lower average outstanding borrowings and lower average interest rates. For the year ended December 31, 2019,
our weighted average debt outstanding on our Owl Rock credit facility and revolving credit facility combined was $55.0
million. For the year ended December 31, 2018, our weighted average debt outstanding on our Owl Rock credit facility and
prior revolving credit facility combined was $86.9 million. Our weighted average interest was 7.29% and 8.10% for the years
ended December 31, 2019 and 2018, respectively. In July 2018, proceeds from the Owl Rock credit facility were used to fully
repay the outstanding balance of the prior revolving credit facility. In May 2019, a portion of the net proceeds received from the
75
ff
IPO were used to full
y repay the outstanding borrowings under the Owl Rock credit facility. In December 2019, a portion of the
net proceeds received from the December 2019 Offering were used to fully repay the outstanding borrowings under our
revolving credit facility. See “Note 7—Long-Term Debt” and “Note 1—Business and Basis of Presentation” to the consolidated
ncial statements of Brigham Minerals, Inc. as of December 31, 2019 included elsewhere in this Annual
and combined finaff
Report for further discussion of this transaction.
Loss on extinguishment of debt. As a result of the full repayment of the outstanding balance of the Owl Rock credit
facility of $200.0 million in May 2019, we recognized a loss on extinguishment of debt of approximately $6.9 million. The loss
alized debt issuance costs, a $2.1 million prepayment fee
on extinguishment of debt consisted of a $4.0 million write-off of capita
and legal fees of $0.8 million. See “Note 7—Long-Term Debt” to the consolidated and combined finaff
ncial statements of
Brigham Minerals, Inc. as of December 31, 2019 included elsewhere in this Annual Report for further discussion of these
transactions.
to oil derivative instruments. We realized $0.5 million of gains on our settled derivative instruments during
For the year ended December 31, 2019, we recognized a loss on derivative instruments, net of $0.6 million, which is
attributablea
the year
ended December 31, 2019. For the year ended December 31, 2018, we recognized a net gain on derivative instruments of $0.4
to derivative instruments based on the price of oil. We realized $0.8 million of losses on our
million, which is attributablea
d
settled derivative instruments during
the year ended December 31, 2018.
d
Factors Affecting the Comparability of Our Results of Operations to Our Historical Results of Operations
Our future results of operations may not be comparable to our historical results of operations for the periods presented,
primarily for the reasons described below.
Corporate Reorganization and Transactions
The historical consolidated and combined finaff
ncial statements included in this Annual Report for periods on or before
April 23, 2019 are based on the financial statements of our predecessor and Brigham Minerals prior to our corporate
reorganization consummated in connection with our IPO. As a result, such historical consolidated and combined finaff
ncial data
may not give you an accurate indication of what our actual results would have been if the corporate reorganization had been
completed at the beginning of the periods presented or of what our future results of operations are likely to be.
In April 2019, Brigham Minerals completed the IPO of 16,675,000 shares of Class A common stock at a price to the
public of $18.00 per share. As a result of the IPO, Brigham Minerals became a holding company whose sole material asset
consisted of a 43.3% interest in Brigham LLC, which wholly owns Brigham Resources. Brigham Resources continues to
wholly own the Minerals Subsidiaries, which own all of Brigham Resources’ operating assets. In connection with the IPO,
Brigham Minerals became the sole managing member of Brigham LLC and is responsible for all operational, management and
administrative decisions relating to Brigham LLC’s business and consolidates the financial results of Brigham LLC and its
wholly-owned subsidiary, Brigham Resources.
On December 16, 2019, Brigham Minerals completed an offering of 12,650,000 shares of its Class A common stock (the
"December 2019 Offering"), including 6,000,000 shares issued and sold by Brigham Minerals and an aggregate of 6,650,000
shares sold by certain shareholders of the Company, of which 5,496,813 represents shares issued upon
redemption of an
equivalent number of their Brigham LLC units, at a price to the public of $18.10 per share.
u
On June 12, 2020, Brigham Minerals completed an offering of 6,600,000 shares of its Class A common stock (the "June
2020 Secondary Offering"), all of which were sold by certain shareholders of the Company (the “June 2020 Selling
Shareholders”), and 4,872,669 of which represented shares issued upon
redemption of an equivalent number of the June 2020
Selling Shareholders’ Brigham LLC Units (together with a corresponding number of shares of Class B common stock in
Brigham Minerals), at a price to the public of $13.75 per share. Brigham Minerals did not sell any shares of its common stock
in the June 2020 Secondary Offering and did not receive any proceeds pursuant to the June 2020 Secondary Offering.
u
On September 15, 2020, Brigham Minerals completed an offering of 5,021,140 shares of its Class A common stock,
including 654,931 shares issued pursuant to the option granted to the underwriter to purchase additional shares to cover over-
allotments (the "September 2020 Secondary Offering"), all of which were sold by certain shareholders of the Company (the
"September 2020 Selling Shareholders"), and 3,062,011 of which represented shares issued upon
redemption of an equivalent
number of the September 2020 Selling Shareholders’ Brigham LLC Units (together with a corresponding number of shares of
Class B common stock in Brigham Minerals), at a price to the public of $8.20 per share. Brigham Minerals did not sell any
u
76
shares of its Class A common stock in the September 2020 Secondary Offering and did not receive any proceeds pursuant to the
September 2020 Secondary Offering. In addition, in connection with the September 2020 Secondary Offering, Brigham
Minerals repurchased 436,630 shares of its Class A common stock from the September 2020 Selling Shareholders in a privately
negotiated transaction at a price equal to the price per share at which the underwriter purchased shares from the September 2020
Selling Shareholders in the September 2020 Secondary Offering (and Brigham LLC redeemed a corresponding number of
Brigham LLC Units held by Brigham Minerals). The repurchased shares are presented in the Company's condensed
consolidated balance sheet as Treasury Stock, at cost.
Following the completion of the September 2020 Secondary Offering and as of December 31, 2020, Brigham Minerals
owned a 76.8% interest in Brigham LLC and the Original Owners owned 23.2% of the outstanding voting stock of Brigham
Minerals. Certain other entities affiliated with Yorktown Partners LLC and Pine Brook Road Advisors, LP, which are a subset
of the Company's Original Owners, collectively owned 16.9% of the outstanding voting stock of Brigham Minerals as of
December 31, 2020.
The corporate reorganization that was completed contemporaneously with the closing of the IPO provided a mechanism
by which the Brigham LLC Units to be allocated amongst the Original Owners, including the holders of our management
incentive units, was determined. As a result, the satisfaction of all conditions relating to the vesting of certain management
incentive units held in Brigham Equity Holdings, LLC (“Brigham Equity Holdings”) by our management and employees
became probable. Accordingly, at IPO, we recognized a cumulative effect adjustment to share-based compensation cost of
approximately $2.0 million pertaining to the period from the grant date through the IPO date, related to the estimated fair value
of the Incentive Units (as defined in “Note 10—Share-based Compensation—LLC Incentive Units” to the consolidated and
combined finaff
ncial statements of Brigham Minerals included elsewhere in this Annual Report) at grant, all of which was non-
cash.
Income Taxes
Brigham Minerals is subject to U.S. federal and state income taxes as a corporation. Our predecessor was treated as a
flow-through entity, and is currently treated as a disregarded entity, for U.S. federal income tax purposes and, as such, is
generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to its taxable income is
passed through to its members, including Brigham Minerals. Accordingly, the financial data of our predecessor contains no
provision for U.S. federal income taxes or income taxes in any state or locality (other than franc
hise tax in the State of Texas).
ff
Capital Requirements and Sources of Liquidity
Prior to our IPO, our primary sources of liquidity were capita
al contributions from our Original Owners, borrowings under
our debt arrangements and cash flows from operations. Subsequent to our IPO, our current primary sources of liquidity are cash
flows from operations, borrowings under our revolving credit facility and proceeds from any primary issuances of equity
securities. Future sources of liquidity may also include other credit facff
ilities we may enter into in the future and additional
issuances of debt or equity securities. As a result of the COVID-19 pandemic and the decline in commodities prices, coupled
al expenditures in 2020 and beyond, our
with many of our operators announcing significant reductions in projected capita
revenues and cash flows from operations have been and may continue to be negatively impacted and we may not have access to
capita
al markets on terms favorabl
e to us or at all.
ff
Our primary uses of capita
al are for the payment of dividends to our stockholders and for investing in our business,
specifically the acquisition of additional mineral and royalty interests. In connection with the ongoing COVID-19 pandemic and
the announced reductions in projected capita
al expenditures by our operators, our cash flows from operations have been and may
continue to be negatively impacted, and as a result, the dividend amount we are able to pay our stockholders has been and may
also continue to be negatively impacted.
As a mineral and royalty interest owner, we incur the initial cost to acquire our interests, but thereafter do not incur any
al expenditures or lease operating expenses, which are entirely borne by the operator. As a result, the vast
development capita
al expenditures are related to our acquisition of additional mineral and royalty interests. The amount and
majoa rity of our capita
allocation of future acquisition-related capital expenditures will depend upon a number of facff
tors, including the number and
size of acquisition opportunities, our cash flows from operations, investing and financing activities and our ability to assimilate
acquisitions. For the year ended December 31, 2020, we deployed approximately $72.7 million for acquisition-related capital
alized share-based compensation cost. We periodically assess changes in current
expenditures,
ors to determine the effects
and projected free cash flows, acquisition and divestituret
activities, debt requirements and other fact
inclusive of a $6.1 million capita
ff
t
77
t
u
our current oil, natural
on our liquidity. Based upon
gas and NGL price expectations for the year ended December 31, 2021, we
believe that our cash flow from operations and additional borrowings under our revolving credit facility will provide us with
sufficient liquidity to execute our current strategy. However, our ability to generate cash is subject to a number of facff
tors, many
of which are beyond our control, including commodity prices, weather and general economic, financial, competitive, legislative,
regulatory and other facff
al through
partnerships, asset sales, offerings of equity and debt securities or other means. If we are
additional borrowings, joint venturet
unable to obtain funds when needed or on acceptablea
e
terms, we may not be able to complete acquisitions that may be favorabl
to us.
tors. If we require additional capital for acquisitions or other reasons, we may seek such capita
ff
As of December 31, 2020, our liquidity was as follows:
Cash and cash equivalents
Revolving credit facility availability
Total Liquidity
Working Capital
(In millions)
$
$
$
9.1
115.0
124.1
Our working capita
al, which we definff e as current assets minus current liabilities, totaled $22.6 million as of December 31,
2020, as compared to $71.6 million at December 31, 2019. Our collection of receivables has historically been timely, and losses
associated with uncollectible receivables have historically not been significant.
When new wells are turned to sales, our collection of receivables has lagged approximately six months from initial
production as operators complete the division order process, at which point we are paid in arrears and then kept current. Our
cash and cash equivalents balance totaled $9.1 million and $51.1 million at December 31, 2020 and December 31, 2019,
respectively. The decrease in cash and cash equivalents was primarily due to acquisitions made and payment of dividends to our
stockholders during the year ended December 31, 2020 . See "Note 4—Acquisitions and Divestitures" to the consolidated and
ncial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion. We expect
combined finaff
that our cash flows from operations and additional borrowings under our revolving credit facility will be sufficient to fund our
al needs. We expect that the pace of our operators’ drilling and completion of our undeveloped locations,
working capita
production volumes, commodity prices and differentials to WTI and Henry Hub prices for our oil, natural
gas and NGL
production will be the largest variablea
s affecting our working capita
al.
t
Dividends
The following tablea
ff
sets forth
information with respect to cash dividends and distributions declared by our board of
directors during 2020:
Declaration Date
February 27, 2020
May 11, 2020
August 6, 2020
Record Date
March 12, 2020
May 27, 2020
August 27, 2020
November 4, 2020
November 30, 2020
(1) Dividends paid to holders of Class A common stock.
Payment Date
March 19, 2020
June 3, 2020
September 3, 2020
December 7, 2020
Total:
$
$
Dividend Amount
Dividends paid
(in thousands) (1)
0.38
0.37
0.14
0.24
1.13
$
$
12,969
12,803
5,567
10,877
42,216
The decision to pay any future dividends is solely within the discretion of, and subject to approva
l by, our board of
directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date
and the actual amount of the dividend, will depend upon our results of operations, financial condition, capita
al requirements,
contractual restrictions, restrictions imposed by applicable law and other facff
tors that the board deems relevant at the time of
such determination. See "Item 5—Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities—Dividend Policy" for further discussion of our dividend policy.
a
Cash Flows
The following tablea
summarizes our cash flows for the periods indicated:
78
(In thousands)
Net cash provided by operating activities
Net cash used in investing activities
Net cash (used in)/provided by financing activities
Year Ended December 31,
2020
2019
2018
$
75,260
$
69,025
$
31,444
(65,425)
(51,824)
(216,832)
(195,268)
166,481
189,397
Analysis of Cash Flow Changes Between the Years Ended December 31, 2020, 2019 and 2018
Net cash provided by ob
peo ratingii
activtt
itiett s
Net cash provided by operating activities is primarily affected by production volumes, the prices of oil, natural
gas and
NGLs, lease bonus revenue and changes in working capita
the
year ended December 31, 2020 as compared to the year ended December 31, 2019 is primarily due to improved collections of
receivables and reduced payments forff
interest and income taxes, partly offset by increased payments for operating expenses.
al. The increase in net cash provided by operating activities forff
t
The increase in net cash provided by operating activities forff
the year ended December 31, 2019 as compared to the year
ended December 31, 2018 is primarily due to: (i) a 91% increase in production volumes and the 14% decrease in realized prices
during the year ended December 31, 2019 discussed above; (ii) increases in operating expenses; and (iii) lower lease bonus
revenues.
Net cash used in i
ii nvii
esting an
ctivtt
itiett s
Net cash used in investing activities is primarily composed of acquisitions of mineral and royalty interests, net of
dispositions. For the year ended December 31, 2020, our net cash used in investing activities was primarily a result of
acquisitions of mineral and royalty interests totaling $66.5 million and other fixeff
d assets totaling $0.5 million, offset by sales of
mineral and royalty interests totaling $1.6 million.
For the year ended December 31, 2019, our net cash used in investing activities was primarily a result of acquisitions of
d assets of $0.4 million, offset by sales of
mineral and royalty interests totaling $219.5 million and additions to other fixeff
mineral and royalty interests totaling $3.1 million.
For the year ended December 31, 2018, our net cash used in investing activities was primarily a result of acquisitions of
d assets of $0.7 million. Our cash flows from
the year ended December 31, 2018 also reflects $0.9 million of proceeds from the sale of equity
mineral and royalty interests totaling $195.6 million and additions to other fixeff
investing activities forff
securities.
Net cash (used in)/pr
ii
ovidedii
by financing activtt
itiett s
Net cash used in financing activities forff
the year ended December 31, 2020 was primarily a result of dividends paid to
holders of our Class A common stock of $42.2 million, distributions to holders of temporary equity of $24.7 million, the
repurchase of shares of our Class A common stock from the September 2020 Selling Shareholders for an aggregate purchase
price of approximately $3.5 million, and payment related to employee tax withholding for settlement of share-based
compensation awards of $1.2 million. This was partially offset by borrowings under our revolving credit facility of $20.0
million.
ncing activities forff
Net cash provided by finaff
the year ended December 31, 2019 included the combined net proceeds
generated from the IPO and December 2019 Offering of $379.8 million offset by the combined full repayment of the
outstanding balances of the Owl Rock credit facility and revolving credit facility of $175.0 million (net of additional
borrowings of $105.0 million incurred during the year), dividends paid to holders of our Class A common stock of $14.7
million, distributions to holders of temporary equity of $20.1 million, payment of debt extinguishment fees of $2.1 million and
payment of loan closing costs of $1.3 million.
ncing activities forff
Net cash provided by finaff
al
contributions from the Original Owners and $213.4 million in additional borrowings under our prior revolving credit facility
and the Owl Rock credit facility combined, net of $4.6 million in associated loan closing costs. This was partially offset by
payment of $70.0 million to pay off and terminate the prior revolving credit facility on July 28, 2018 using funds from the new
term loan facff
the year ended December 31, 2018 included $46.0 million in net capita
ility.
79
Owl Rock Credit Facility
al Corporation, as administrative agent and
On July 27, 2018, we entered into a credit agreement with Owl Rock Capita
ct to customary fees, guarantees of
collateral agent (our “Owl Rock credit facility”). Our Owl Rock credit facility was subjeu
subsidiaries, restrictions and covenants, including certain restricted payments, and was collateralized by certain of our royalty
and mineral properties.
Our Owl Rock credit facility provided forff
a $125.0 million initial term loan and a $75.0 million delayed draw term loan
(“DDTL”). Also, a $10.0 million revolving credit facility was available for general corporate purposes, which was undrawn as
of May 7, 2019. Our Owl Rock credit facility bore interest at a rate per annum equal to, at our option, (a) the base rate plus
4.50%, or (b) the adjusted LIBOR rate forff
such interest period (subject to a 1.00% floor) plus 5.50%. We used a portion of the
proceeds from the IPO to repay the outstanding borrowings under the term loan portion and DDTL portion of our Owl Rock
credit facility and terminated the Owl Rock credit facility on May 7, 2019. See “Note 7—Long-Term Debt” to the consolidated
and combined financial statements of Brigham Minerals included elsewhere in this Annual Report for further discussion.
Prior Revolving Credit Facility
Prior to entering into our Owl Rock credit facility (which was terminated in May 2019), we maintained a revolving credit
facility (our “prior revolving credit facility”) with Wells Fargo Bank, N.A., as administrative agent, and certain lenders party
thereto with commitments of $150.0 million (subject to a borrowing base). We repaid the $70.0 million outstanding balance
under our prior revolving credit facility with proceeds from our Owl Rock credit facility and terminated the prior revolving
credit facility. The borrowing base at the time of termination was $70.0 million.
Revolving Credit Facility
On May 16, 2019 (the “closing date”), Brigham Resources entered into a credit agreement with Wells Fargo Bank, N.A.,
as administrative agent for the various lenders from time to time party thereto, providing for a revolving credit facility (our
“revolving credit facility”). Our revolving credit facility is guaranteed by Brigham Resources’ domestic subsidiaries and is
collateralized by a lien on substantial portion of Brigham Resources and its domestic subsidiaries’ assets, including substantial
portion of their respective royalty and mineral properties.
Availability under our revolving credit facility is governed by a borrowing base, which is subject to redetermination in
May and November of each year. In addition, lenders holding two-thirds of the aggregate commitments may request one
additional redetermination each year. Brigham Resources can also request one additional redetermination each year, and such
other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to further
adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of
permitted additional indebtedness. Increases to the borrowing base require unanimous approval of the lenders, while decreases
only require approval of lenders holding two-thirds of the aggregate commitments at such time. As of December 31, 2020, the
borrowing base on our revolving credit facility was $135.0 million, with outstanding borrowings of $20.0 million, resulting in
$115.0 million availabila
future borrowings.
ity forff
Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the
margin is based on utilization of our revolving credit facility
adjusted LIBOR rate plus an applicable margin. The applicablea
and ranges fromff
(a) in the case of adjusted base rate loans, 0.750% to 1.750% and (b) in the case of adjusted LIBOR rate loans,
1.750% to 2.750%. Brigham Resources may elect an interest period of one, two, three, six, or if available to all lenders, twelve
in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee
months. Interest is payablea
quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount
is payablea
ranging from 0.375% to 0.500% based on utilization of our revolving credit facility. Our revolving credit facff
ility is subject to
other customary fee, interest and expense reimbursement provisions.
Our revolving credit facility matures on May 16, 2024. Loans drawn under our revolving credit facility may be prepaid at
any time without premium or penalty (other than customary LIBOR breakage) and must be prepaid in the event that exposure
exceeds the lesser of the borrowing base and the elected availabila
ity at such time. The principal amount of loans that are prepaid
are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be
reborrowed. In addition, Brigham Resources may permanently reduce or terminate in full
the commitments under our revolving
credit facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid.
Upon the occurrence of an event of default under our revolving credit facility, the administrative agent acting at the direction of
the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all
ff
80
commitments under our revolving credit facility, provided that such acceleration and termination occurs automatically upon
occurrence of a bankruptcy or insolvency event of default.
u
the
Contractual Obligations
A summary of our contractual obligations as of December 31, 2020 is provided in the following tabla e:
(In thousands)
2021
2022
2023
2024
2025
Thereafter
Total
Long-term debt obligations (1) (2)
$
— $
— $
— $ 20,000
$
— $
— $ 20,000
Office lease
Total
1,272
1,310
1,347
1,383
1,419
$ 1,272
$ 1,310
$ 1,347
$ 21,383
$ 1,419
$
2,251
2,251
8,982
$ 28,982
By Year
(1) As of December 31, 2020, the borrowing base on our revolving credit facility
$115.0 million availability for future borrowings.
(2) Does not include future unutilized fees, amortization of deferred financing costs, interest expense or other fees related to our revolving credit facility
because we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.
was $135.0 million, with outstanding borrowings of $20.0 million, resulting in
ff
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated and
ncial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated and
combined finaff
combined finaff
ncial statements requires it to make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Changes in facts and circumstances
or additional information may result in revised estimates, and actual results may differ fromff
these estimates.
A complete list of our significant accounting policies are described in the notes to our audited consolidated and combined
financial statements forff
the year ended December 31, 2020 included elsewhere in this Annual Report.
Use of Estimates
The preparation of consolidated and combined finaff
ncial statements in conformity with GAAP requires management to
make estimates and assumptim ons that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure
ncial statements and accompanying notes. Although
of contingent assets and liabilities in the consolidated and combined finaff
management believes these estimates are reasonable, actual results could differ fromff
these estimates. Changes in estimates are
recorded prospectively.
t
Our consolidated and combined finaff
gas and NGL reserves that are the basis for the calculations of DD&A and impairment of oil and natural
ncial statements are based on a number of significant estimates including quantities of
gas
oil, natural
t
gas and
properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural
gas reserves. The accuracy of any
there are numerous uncertainties inherent in estimating quantities of proved oil and natural
ion of the quality of available data and of engineering and geological interpretation and judgment. As
reserve estimate is a funct
a result, reserve estimates may differff
gas that are ultimately recovered. Our reserve
estimates are audited by CG&A, an independent petroleum engineering firm. Other items subject to significant estimates and
gas properties, valuation of derivative instruments and revenue
assumptim ons include the carrying amount of oil and natural
accruals.
from the quantities of oil and natural
ff
t
t
t
t
Receivables
Receivables consist of mineral and royalty income due from operators for oil and gas sales to purchasers. Those purchasers
remit payment for production to the operator of the properties and the operator, in turn, remits payment to us. Receivables from
third parties forff which we did not receive actual information, either dued
to timing delays or due to the unavailability of data at
the time when revenues are recognized, are estimated. Volume estimates for wells with available historical actual data are based
the months the historical
upon (i) the historical actual data forff
actual data is not available. We do not recognize revenues for wells with no historical actuat
l data because we cannot conclude
that it is probable that a significant revenue reversal will not occur in future periods. Pricing estimates are based upon actual
the average basis differential from market on a basin-by-basin basis.
prices realized in an area by adjusting the market price forff
, or (ii) engineering estimates forff
the months the data is availablea
81
We routinely review outstanding balances, assess the financial strength of our operators and record a reserve for amounts
not expected to be fully recovered. We recorded an allowance for doubtful accounts of $0.3 million, $0.6 million and $0.4
million for the years ended December 31, 2020, 2019 and 2018, respectively.
Oil and Gas Properties
We use the full cost method of accounting for our oil and natural
t
incurred for the purpose of acquiring mineral and royalty interests and certain related employee costs are capita
cost pool. Costs associated with general corporate activities are expensed in the period incurred.
gas properties. Under this method, all acquisition costs
alized into a full
ff
Capita
alized costs are amortized using the units-of-production method. Under this method, the provision for depletion is
calculated by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the
total unamortized cost base by the net equivalent proved reserves at the beginning of the period.
Costs associated with unevaluated properties are excluded from the amortizable cost base until a determination has been
made as to the existence of proved reserves. Unevaluated properties are reviewed periodically to determine whether the costs
incurred should be reclassified to the full cost pool and subjected to amortization. The costs associated with unevaluated
alized interest. Unevaluated properties are assessed for
properties primarily consist of acquisition and leasehold costs and capita
impairment on an individual basis or as a group if properties are individually insignificant. The assessment
includes
consideration of the following factors, among others: expectation of future drilling activity; past drilling results and activity;
geological and geophysical evaluations; the assignment of proved reserves; and the economic viabila
ity of development if
proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative acquisition costs
incurred to date forff
such property are transferred to the full cost pool and are then subject to amortization. There was no
impairment recorded forff
the years ended December 31, 2020, 2019 and 2018.
unevaluated properties forff
Sales and abandonments of oil and natural
as adjustments to the full cost
pool, with no gain or loss recognized unless the adjustments would significantly alter the relationship between capita
alized costs
and proved reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less
than 25% of the reserve quantities of a cost center.
gas properties being amortized are accounted forff
t
Natural gas volumes are converted to Boe at the rate of six thousand Mcf of natural
gas to one Bbl of oil. This convention
is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an
equivalent volume of natural
gas.
t
t
t
alized costs of oil and natural
Under the full cost method of accounting, total capita
gas properties, net of accumulated
depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues fromff
proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated properties, less related income tax
effect
s (full cost ceiling limitation). A write-down of the carrying value of the full cost pool ("impairment charge") is a noncash
ff
charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower depletion expense in
future periods. A ceiling limitation is calculated at each reporting period. The ceiling limitation calculation is prepared using the
gas price ("SEC gas price") as of the first day of each
unweighted arithmetic average of oil price ("SEC oil price") and natural
t
the trailing 12-month period ended, as required under the guidelines established by the SEC. As of December 31,
month forff
2020, 2019 and 2018, the SEC oil prices were $39.57, $55.65, and $65.66, respectively, per barrel forff
r adjusted by
energy content, transportation fees and regional price diffff erff entials and the SEC gas prices were $2.00, $2.60, and $3.12,
area forff
respectively, per MMBtu for natural
energy content, transportation fees and regional price
differentials. As a result of the decline in the SEC oil prices and SEC gas prices during the twelve months ended December 31,
2020, and taking into consideration certain reclassification of proved undeveloped reserves to probable and possible reserves
during the three months ended December 31, 2020, as a result of a slowdown in operator activity, the net book value of oil and
natural
resulting in an
t
impaim rment charge of $79.6 million to oil and gas properties, net during the year ended December 31, 2020. There were no
impairment charges during
gas properties exceeded the ceiling limitation as of September 30, 2020 and December 31, 2020,
the years ended December 31, 2019 and 2018.
r adjusted by area forff
ff
gas, furthe
ff
oil, furthe
d
t
Future declines in the unweighted arithmetic average SEC oil prices used in the full cost ceiling test may result in
additional impairment charges in the future and such impairments could be material. In addition to the impact of lower prices,
any future changes to assumptim ons of drilling and completion activity, development timing, acquisitions or divestitures
of oil
and gas properties, proved undeveloped locations, and production and other estimates may require revisions to estimates of total
proved reserves which would impact the amount of any impairment charge.
t
82
During the year ended December 31, 2020, Brigham Minerals reduced its proved undeveloped reserves by 8,209 MBoe
primarily due to a reclassification of 7,036 MBoe from proved undeveloped reserves to probable and possible reserves, as a
result of decreased rig activity, a 29% reduction in SEC oil prices over the twelve months ended December 31, 2019, and
conversion from proved undeveloped to proved developed reserves. The reduction in rig activity led to changes in the
development timing and a reduction of the number of proved undeveloped locations that Brigham Minerals expects will be
developed within fiveff
years after the date of booking.
We engage CG&A, our independent petroleum engineering firm, to audit our total estimated proved, probable and
possible reserves. We expect proved, probable and possible reserve estimates will change as additional information becomes
available and as commodity prices and costs change. We evaluate and estimate our proved, probable and possible reserves
internally each quarter and CG&A audits our proved, probable and possible reserves annually. Reserve estimates are inherently
imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The estimates of
proved, probable and possible reserves are based upon the use of technical and economic data including, but not limited to, well
logs, geologic mapsa , seismic data, well test data, production data, historical price and cost information, historical and future
operator development plans, and property ownership interests. Standard engineering and geoscience methods, such as reservoir
modeling, performance analysis, volumetric analysis and analogy, which are considered to be appropri
ate and necessary to
sh reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, are also used.
establia
As in all aspects of oil and natural
gas evaluation, there are uncertainties inherent in the interpretation of engineering and
geoscience data; therefore, these estimates necessarily represent only informed professional judgment.
a
t
ff
It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates
gas reserves, the remaining estimated lives of oil and
economic
economic volumes generally increase per unit
of future cash inflows,
natural
t
volumes generally reduce per unit depletion rates while decreases in recoverablea
depletion rates.
gas properties or any combination of the above may be increased or reduced. Increases in recoverablea
future gross revenue, the amount of oil and natural
t
It should not be assumed that the standardized measure included in this report as of December 31, 2020 is the current
market value of our estimated proved reserves. In accordance with SEC requirements, we based the 2020 standardized measure
on the SEC oil price and SEC gas price as of December 31, 2020, and prevailing costs on the date of the estimate. Actual future
prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Item 1—Business—
Oil, Natural Gas, and NGLs Data—Proved,
Probable and Possible Reserves” and “Item 1A—Risk Factors” for additional
information regarding estimates of proved, probable and possible reserves.
aa
ff
Revenue from Contracts with Customers
In 2019, we adopted the Financial Accounting Standards Board's ("FASB") Accounting Standards Codification Topic
606, Revenue from Contracts with Customers, ("ASC 606") using the modified retrospective approach, which only applied to
contracts that were in effect as of the date of adoption. The adoption did not require an adjustment to opening retained earnings
for the cumulative effect adjustment and did not impact our previously reported results of operations, nor our ongoing
consolidated and combined balance sheets, statements of cash flowff
or statements of changes in shareholders' and members'
equity. Overall, there were no material changes in the timing of the satisfaction of our performance obligations or the allocation
d to legacy U.S. GAAP.
of the transaction price to our performance obligations in applying the guidance in ASC 606 as comparem
Oil and natural gas sales
t
Oil, natural
gas and NGLs sales revenues are generally recognized when control of the product is transferred to the
customer, the perfoff rmance obligations under the terms of the contracts with customers are satisfied and collectability is
reasonably assured. As a non-operator, we have limited visibility into the timing of when new wells start producing and
production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are
required to estimate the amount of production delivered to the purchaser and the price that we will receive forff
the sale of the
product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable
line item in the accompanying consolidated and combined balance sheets. The difference
between our estimates and the actual
amounts received for oil and natural
gas sales is recorded in the month that payment is received from the third party.
ff
t
Lease bonus and other
tt
income
We earn revenue from lease bonuses, delay rentals, and right-of-way payments. We generate lease bonus revenue by
leasing our mineral interests to exploration and production companies. A lease agreement represents our contract with a
customer and generally transfers the rights to any oil or natural
gas discovered, grants us a right to a specified royalty interest,
and requires that drilling and completion operations commence within a specified time period. We recognize lease bonus
revenues when the lease agreement has been executed, payment has been received, and we have no further obligation to refund
the payment. At the time we execute the lease agreement, we expect to receive the lease bonus payment within a reasonable
t
83
time, though in no case more than one year, such that we have not adjusted the expected amount of consideration for the effects
of any significant financing component per the practical expedient in ASC 606.
Share-Based Compensation
Brigham Minerals accounts for its share-based compensation, including grants of the Incentive Units, restricted stock
awards, time-based restricted stock units and performance-based stock units, in the condensed consolidated and combined
r values at grant date. Brigham Minerals uses a Monte Carlo simulation to
statements of operations based on their estimated faiff
determine the fair value of performance-based stock units. Brigham Minerals recognizes expense on a straight-line basis over
the vesting period of the respective grant, which is generally the requisite service period. Brigham Minerals capitalizes a portion
of the share-based compensation cost to oil and gas properties on the consolidated and combined balance sheets. Share-based
compensation expense is included in general and administrative expenses in Brigham Minerals’ consolidated and combined
statements of operations included within this Annual Report. There was approximately $17.0 million of unamortized
compensation expense relating to outstanding awards at December 31, 2020, a portion of which will be capita
alized. The
unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the
awards. Brigham Minerals accounts for forfeitures as they occur.
Income Taxes
Brigham Minerals accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are
recognized for the future tax consequences attributablea
to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing
tax laws and the rates expected to appl
y to taxable income in the years in which those temporary differences are expected to be
recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the
period that includes the enactment date.
a
We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize our
deferred income tax assets, including net operating losses. In making this determination, we consider all available positive and
negative evidence and make certain assumptim ons. We consider, among other things, our deferred tax liabia lities, the overall
business environment, our historical earnings and losses, current industry trends and our outlook for futuret
years.
Temporary Equity
Brigham Minerals accounts for the Original Owners’ 23.2% interest in Brigham LLC (as of December 31, 2020) as
temporary equity as a result of certain redemption rights held by the Original Owners as discussed in “Note 9—Temporary
Equity” to the consolidated and combined finaff
ncial statements of Brigham Minerals included elsewhere in this Annual Report.
As such, Brigham Minerals adjusts temporary equity to its maximum redemption amount at the balance sheet date, if higher
than the carrying amount. The redemption amount is based on the 10-day volume-weighted average closing price (“VWAP”) of
Class A shares at the end of the reporting period. Changes in the redemption value are recognized immediately as they occur, as
if the end of the reporting period was also the redemption date forff
the instrument, with an offsetting entry to additional paid-in
to permanent equity (i) upon Conversion of Class B common stock (and an equivalent
capita
number of Brigham LLC Units) to Class A common stock, or (ii) when holders of Class B common stock no longer control a
majori
ty of the votes of the board of directors through direct representation on the board of directors, and no longer control the
a
determination of whether to make a cash payment upon a Brigham Unit Holder's exercise of its Redemption Right.
al. Temporary equity is reclassifiedff
Recently Issued Accounting Pronouncements
See “Note 2—Significant Accounting Policies—Recently Issued Accounting Standards Not Yet Adopted” in our
a discussion of recent accounting
ncial statements included elsewhere in this Annual Report, forff
consolidated and combined finaff
pronouncements.
We are an “emerging growth company,” under the JOBS Act, which allows us to take advantage of an extended transition
period for complying with new or revised accounting standards pursuant to Section 107(b) of the JOBS Act.
84
Internal Controls and Procedures
r
Upon becoming a public company, we were required to comply with the SEC’s rules implementing Section 302 and
s-Oxley Act, which requires our management to certify financial and other information in our
Section 404 of the Sarbane
quarterly and annual reports, and, for the year ended December 31, 2020, provide an annual management report on the
effectiveness of our internal control over financial reporting. In addition, we will be required to have our independent registered
public accounting firm attest to the effectiveness of our internal control over financial reporting under Section 404 beginning
to our ceasing to be an “emerging growth company” within the meaning of
with our first annual report subsequent
Section 2(a)(19) of the Securities Act.
As of December 31, 2020, we did not have any material off-balance sheet arrangements.
Off-Balance Sheet Arrangements
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as
described below. The primary objective of the following information is to provide quantitative and qualitative information
about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in
gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future
oil, natural
losses, but rather indicators of reasonably possible losses. This forwar
d-looking information provides indicators of how we
view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for
purposes other than speculative trading.
ff
t
Commodity Price Risk
t
t
gas and NGLs has been volatile and unpredictable forff
Our majora market risk exposure is in the pricing that our operators receive for the oil, natural
gas and NGLs produced
gas and
t
from our properties. Realized prices are primarily driven by the prevailing global prices for oil and prices for natural
NGLs in the United States. Pricing for oil, natural
several years, and we
expect this volatility to continue in the future. During the past fivff e years, the posted price forff WTI has ranged from a historic,
record low price of negative ($36.98) per barrel in April 2020 to a high of $77.41 per barrel in June 2018, and as
of December 31, 2020, the posted price forff
oil was $48.35 per barrel. NGL prices generally correlate to the price of oil, and
accordingly prices for these products have likewise declined and are likely to continue following that market. Prices forff
domestic natural
ub
gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $6.24 per MMBtu
spot market price forff
gas was $2.36 per MMBtu. The
ub spot market price of natural
in January 2018, and as of December 31, 2020, the Henry Hrr
prices our operators receive for the oil, natural
our properties depend on numerous factors beyond
their and our control, some of which are discussed in “Item 1A—Risk Factors—Risks Related to Our Business—Substantially
all of our revenues are derived from royalty payments that are based on the price at which oil, natural
gas and NGLs produced
gas and NGLs are volatile due to factors beyond our
from the acreage underlying our interests are sold. Prices of oil, natural
control. The significant drop in the price of oil in 2020 has adversely affected, and any further decline in commodity prices in
the future may adversely affecff
gas have also fluctuated significantly over the last several years. During the past fivff e years, the Henry Hrr
t our business, financial condition or results of operations.”
gas and NGLs produced fromff
t
natural
t
t
t
t
t
A $1.00 per barrel change in our realized oil price would have resulted in a $1.8 million change in our oil revenues for
gas price would have resulted in a $0.6
the year ended December 31, 2020. A $0.10 per Mcf change in our realized natural
million change in our natural
the year ended December 31, 2020. A $1.00 per barrel change in NGL prices
would have resulted in a $0.7 million change in our NGL revenues for the year months ended December 31, 2020. Royalty
revenues from oil sales contributed 74% of our total revenues for the year ended December 31, 2020. Royalty revenue from
natural
gas sales contributed 11% and royalty revenue from NGL sales contributed 9% of our total revenues for the year ended
t
December 31, 2020.
gas revenues forff
t
t
We may enter into derivative instruments, such as collars, swapsa
and basis swaps, to partially mitigate the impact of
commodity price volatility. These hedging instruments allow us to reduce, but not eliminate, the potential effects of the
variability in cash flow from operations due to fluctuations in oil, natural
gas and NGL prices and provide increased certainty of
cash flows for our debt service requirements. However, these instruments provide only partial price protection against declines
gas and NGL prices and may partially limit our potential gains from future increases in prices. Our revolving
in oil, natural
t
t
85
credit facility allows us to hedge up to 85% of our reasonablya
and natural gas, calculated separately, for up to 60 months in the futff ure.
t
anticipated projected production from our proved reserves of oil
We did not have any oil or gas derivative contracts in place as of December 31, 2020 and December 31, 2019.
Counterparty and Customer Credit Risk
When we enter into them, our derivative contracts expose us to credit risk in the event of nonperformance by
counterparties. While we do not require counterparties to our derivative contracts to post collateral, we evaluate the credit
standing of such counterparties as we deem appropria
te.
a
Our principal exposures to credit risk are through receivables generated by the production activities of our operators. The
inabila
lure of our significant operators to meet their obligations to us or their insolvency or liquidation may adversely
ity or faiff
affect our financial results. See "Item 1A—Risk Factors—Risk Related to Our Business—We may experience delays in the
payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to
lting lessees if any of the operators on those leases declare bankruptcy. We may also experience
terminate our leases with defauff
improper deductions in the payment of royalties."
Interest Rate Risk
Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the
margin is based on utilization of our revolving credit facility
adjusted LIBOR rate plus an applicable margin. The applicablea
and ranges fromff
(a) in the case of adjusted base rate loans, 0.750% to 1.750% and (b) in the case of adjusted LIBOR rate loans,
1.750% to 2.750%. Brigham Resources may elect an interest period of one, two, three, six, or if available to all lenders, twelve
in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee
months. Interest is payablea
quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount
is payablea
ranging from 0.375% to 0.500% based on utilization of our revolving credit facility. Our revolving credit facility is subjec
t to
other customary fee, interest and expense reimbursement provisions. As of December 31, 2020, the borrowing base on our
revolving credit facility was $135.0 million, with outstanding borrowings of $20.0 million, resulting in $115.0 million
availability for futuret
borrowings.
u
Item 8. Financial Statements and Supplementary Data
The Company's consolidated and combined finaff
ncial statements required by this item are included in this Annual
Report beginning on page F-1.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls
tt
and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation
of our management, including our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial
Officer (“CFO”), our principal finaff
ncial officer, the effectiveness of the design and operation of our disclosure controls and
procedures (as definff ed in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2020. Our disclosure
controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the
reports filff ed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the SEC’s rules and forms,
and that such information is accumulated and communicated to our
management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on
ive at December 31,
this evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effect
2020.
ff
ff
Management’s Report
ee
on Internal Control
tt
FF
over Financ
ial Reporting.
ii
As management, we are responsible for establia
shing and maintaining adequate internal control over financial reporting
for the Company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404
86
of the Sarbanes-Oxley Act, we have conducted an assessment, including testing using the criteria in Internal Control—
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
The Company’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the
external purposes in accordance with GAAP.
reliabila
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even
when determined to be effective, can only provide reasonable assurance with respect to finff ancial statement preparation and
presentation.
ncial reporting and the preparation of financial statements forff
ity of finaff
Based on our assessment, we have concluded that the Company maintained effective internal control over financial
reporting as of December 31, 2020, based on criteria in Internal Control—Integrated Framework (2013) issued by COSO.
This Annual Report does not include an attestation report of our independent registered public accounting firm due to a
transition period establia
shed by the rules of the SEC forff
newly public companies.
Changes in Internal
tt
tt
Control
FF
over Financ
ial Reportingii
.
There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the
Exchange Act) that occurred during the fourth quarter of 2020 that have materially affected or are reasonably likely to
materially affect our internal control over financial reporting.
Item 9B. Other Information
Not applicable.
87
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information as to Item 10 is incorporated by reference fromff
the information in our definitive proxy statement for the 2021
Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of
the year ended December 31, 2020.
Item 11. Executive Compensation
Information as to Item 11 is incorporated by reference fromff
the information in our definitive proxy statement for the 2021
Annual Meeting of Stockholders, which we file pursuant to Regulation 14A with the SEC within 120 days after the close of the
year ended December 31, 2020.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information as to Item 12 is incorporated by reference fromff
the information in our definitive proxy statement for the 2021
Annual Meeting of Stockholders, which we file pursuant to Regulation 14A with the SEC within 120 days after the close of the
year ended December 31, 2020.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information as to Item 13 is incorporated by reference fromff
the information in our definitive proxy statement for the 2021
Annual Meeting of Stockholders, which we file pursuant to Regulation 14A with the SEC within 120 days after the close of the
year ended December 31, 2020.
Item 14.
Principal Accounting Fees and Services
Information as to Item 14 is incorporated by reference fromff
the information in our definitive proxy statement for the 2021
Annual Meeting of Stockholders, which we file pursuant to Regulation 14A with the SEC within 120 days after the close of the
year ended December 31, 2020.
88
Item 15. Exhibits, Financial Statement Schedules
(1) Financial Statements
PART IV
The consolidated and combined finaff
ncial statements of Brigham Minerals, Inc. and the Report of Independent Registered
c Accounting Firm are included in Part II, "Item 8— Financial Statements and Supplementary Data” of this Annual
Publiu
Report. Reference is made to the accompanying Index to Financial Statements.
(2) Financial Statement Schedules
All financial statement scheduled
s have been omitted because they are not applicable or the required information is
presented in the financial statements or notes thereto.
(3) Index to Exhibits
The exhibits required to be filed or furnished
ff
pursuant to Item 601 of Regulation S-K are set forth below.
Exhibit
Number
Description
2.1
2.2
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
4.7
Master Reorganization Agreement, dated April 17, 2019, by and among Brigham Minerals, Inc. and the parties named therein
(incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on April 22, 2019)
Contribution and Distribution Agreement, dated April 23, 2019, by and among Brigham Minerals, Inc. and the parties named
therein (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on April 29, 2019)
Amended and Restated Certificate of Incorporation of Brigham Minerals, Inc. (incorporated by reference to Exhibit 3.1 to the
Registrant’s Current Report on Form 8-K filed on April 29, 2019)
Amended and Restated Bylaws of Brigham Minerals, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Current
Report on Form 8-K filed on April 29, 2019)
Registration Rights Agreement, dated April 23, 2019, by and among Brigham Minerals, Inc. and the stockholders named therein
(incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K on April 29, 2019))
Stockholders’ Agreement, dated April 23, 2019, by and among Brigham Minerals, Inc. and the stockholders named therein
(incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on April 29, 2019)
Form of Restricted Stock Unit Grant Notice (incorporated by reference to Exhibit 4.6 to the Registrant’s Registration Statement
on Form S-8 filed on April 23, 2019)
Form of Restricted Stock Unit Grant Notice (Directors) (incorporated by reference to Exhibit 4.7 to the Registrant’s Registration
Statement on Form S-8 filed on April 23, 2019)
Form of Performance Stock Unit Grant Notice (incorporated by reference to Exhibit 4.8 to the Registrant’s Registration
Statement on Form S-8 filed on April 23, 2019)
Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 4.9 to the Registrant’s Registration Statement
on Form S-8 filed on April 23, 2019)
Description of Brigham Minerals, Inc.’s Class A common stock (incorporated by reference to Exhibit 4.7 to the Registrant's
Annual Report on Form 10-K filed on February 28, 2020)
10.1†
Brigham Minerals, Inc. 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.5 to the Registrant’s
Registration Statement on Form S-8 filed on April 23, 2019)
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
Indemnification Agreement (Ben M. Brigham) (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on
Form 8-K filed on April 22, 2019)
Indemnification Agreement (Robert M. Roosa) (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on
Form 8-K filed on April 22, 2019)
Indemnification Agreement (Blake C. Williams) (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report
on Form 8-K filed on April 22, 2019)
Indemnification Agreement (Harold D. Carter) (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on
Form 8-K filed on April 22, 2019)
Indemnification Agreement (John Holland) (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on
Form 8-K filed on April 22, 2019)
Indemnification Agreement (W. Howard Keenan, Jr.) (incorporated by reference to Exhibit 10.6 to the Registrant’s Current
Report on Form 8-K filed on April 22, 2019)
Indemnification Agreement (James R. Levy) (incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on
Form 8-K filed on April 22, 2019)
Indemnification Agreement (Richard Stoneburner) (incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report
on Form 8-K filed on April 22, 2019)
89
Indemnification Agreement (John R. Sult) (incorporated by reference to Exhibit 10.9 to the Registrant’s Current Report on Form
8-K filed on April 22, 2019)
Amended and Restated Limited Liability Company Agreement of Brigham Minerals Holdings, LLC, dated April 23, 2019
(incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on April 29, 2019)
Second Amended and Restated Limited Liability Company Agreement of Brigham Equity Holdings, LLC, dated April 23, 2019
(incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on April 29, 2019)
Credit Agreement, dated as of May 16, 2019, among Brigham Resources, LLC, as borrower, the financial institutions party
thereto, Wells Fargo Bank, N.A., as administrative agent, and Wells Fargo Securities, LLC, as sole lead arranger and sole
bookrunner (incorporated by reference to Exhibit 10.13 to the Registrant’s Quarterly Report on Form 10-Q filed on May 20,
2019)
First Amendment to Credit Agreement, dated as of November 7, 2019, among Brigham Resources, LLC, as borrower, the
financial institutions party thereto, Wells Fargo Bank, N.A., as administrative agent, and Wells Fargo Securities, LLC, as sole
lead arranger and sole bookrunner (incorporated by reference to Exhibit 10.14 to the Registrant's Annual Report on Form 10-K
filed on February 28, 2020)
Second Amendment to Credit Agreement, dated as of February 25, 2020, among Brigham Resources, LLC, as borrower, the
financial institutions party thereto, Wells Fargo Bank, N.A., as administrative agent, and Wells Fargo Securities, LLC, as sole
lead arranger and sole bookrunner (incorporated by reference to Exhibit 10.15 to the Registrant's Annual Report on Form 10-K
filed on February 28, 2020)
First Lien Credit Agreement, dated as of July 27, 2018, by and among Brigham Resources, LLC, Brigham Minerals, LLC, Owl
Rock Capital Corporation, as first lien administrative agent and first lien collateral agent, Owl Rock Capital Advisors LLC, as
the lead arranger and bookrunner, and the lenders and issuing banks party thereto (incorporated by reference to Exhibit 10.4 to
the Registrant’s Registration Statement on Form S-1 on March 18, 2019)
Indemnification Agreement (Carrie Clark) (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form
8-K filed on February 27, 2020)
Indemnification Agreement (A. Lance Langford) (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report
on Form 8-K filed on August 12, 2020)
Subsidiaries of Brigham Minerals, Inc.
Consent of KPMG LLP
Consent of Cawley, Gillespie & Associates, Inc.
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002
Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
Cawley, Gillespie & Associates, Inc., Summary of Reserves of Brigham Resources, LLC at December 31, 2020
The following financial information from this Annual Report on Form 10-K of Brigham Minerals, Inc. for the year ended
December 31, 2020 is formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets,
(ii) Consolidated and Combined Statement of Operations, (iii) Consolidated and Combined Statement of Changes in
Shareholders' and Members' Equity, (iv) Consolidated and Combined Statement of Cash Flows and (v) Notes to the Condensed
Consolidated and Combined Financial Statements, tagged as blocks of text.
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
21.1*
23.1*
23.2*
31.1*
31.2*
32.1*
32.2*
99.1*
101
104
*
†
Filed herewith
Compensatory plan or arrangement.
Item 16.
Form 10-K Summary
None.
90
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this registration
authorized, in the City of Austin, State of Texas.
statement to be signed on its behalf by the undersigned, thereunto dulyd
SIGNATURES
BRIGHAM MINERALRR S, INC.
By:
Name:
/s/ Robert M. Roosa
Robert M. Roosa
Chief Executive Officff er and Director
Date:
February 25, 2021
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capac
a
ities indicated on February 25, 2021.
Name
/s/ Ben M. Brigham
Ben M. Brigham
/s/ Robert M. Roosa
Robert M. Roosa
/s/ Blake C. Williams
Blake C. Williams
/s/ Harold D. Carter
Harold D. Carter
/s/ Carrie Clark
Carrie Clark
/s/ W. Howard Keenan, Jr.
W. Howard Keenan, Jr.
/s/ A. Lance Langford
A. Lance Langford
/s/ James R. Levy
James R. Levy
/s/ Richard Stoneburner
Richard Stoneburner
/s/ John R. Sult
John R. Sult
Title
Executive Chairman
Chief Executive Officff er and Director
(Principal Executive Officff er)
Chief Financial Officer
(Principal Financial Officer and
er)
Principal Accounting Officff
Director
Director
Director
Director
Director
Director
Director
91
INDEX TO FINANCIAL STATEMENTS
BRIGHAM MINERALS, INC.
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2020 and 2019
Consolidated and Combined Statements of Operations for the years ended December 31, 2020, 2019, and 2018
Consolidated and Combined Statements of Comprehensive Income for the years ended December 31, 2020,
2019, and 2018
Consolidated and Combined Statements of Changes in Shareholders' and Members' Equity for the years ended
December 31, 2020, 2019, and 2018
Consolidated and Combined Statements of Cash Flows for the years ended December 31, 2020, 2019, and 2018
Notes to Consolidated and Combined Financial Statements
1. Business and Basis Presentation
2. Significant Accounting Policies
3. Oil and Gas Properties
4. Acquisitions and Divestitures
5. Derivative Instruments
6. Fair Value Measurements
7. Long-Term Debt
8. Shareholders' and Members' Equity
9. Temporary Equity
10. Share-Based Compensation
11. Income Taxes
12. Commitments and Contingencies
13. Related Party
14. COVID-19 Pandemic
15. Subsequent Events
16. Quarterly Financial Information (Unaudited)
17. Reserve and Related Financial Data (SMOG) (Unaudited)
Page
F - 2
F - 3
F - 4
F - 5
F - 6
F - 8
F - 10
F - 10
F - 11
F - 17
F - 18
F - 19
F - 19
F - 20
F - 21
F - 23
F - 24
F - 26
F - 28
F - 29
F - 29
F - 30
F - 30
F - 30
F-1
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
Brigham Minerals, Inc.:
Opinion on the Consolidated and Combined FinFF ancial Statements
We have audited the accompanying consolidated balance sheets of Brigham Minerals, Inc. and subsidiaries (the Company) as
of December 31, 2020 and 2019, the related consolidated and combined statements of operations, comprehensive income (loss),
changes in shareholders’ and members’ equity, and cash flows for each of the years in the three‑year period ended December
31, 2020, and the related notes (collectively, the consolidated and combined finaff
ncial statements). In our opinion, the
ncial statements present fairly, in all material respects, the financial position of the Company as
consolidated and combined finaff
of December 31, 2020 and 2019, and the results of its operations and its cash flows
for each of the years in the three‑year period
ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
ff
Basis for Opinion
These consolidated and combined finaff
ncial statements are the responsibility of the Company’s management. Our responsibility
ncial statements based on our audits. We are a public
is to express an opinion on these consolidated and combined finaff
accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to
be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicablea
rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated and combined finaff
ncial statements are freff e of material
misstatement, whether dued
to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of
its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control
over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control
over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated and combined
financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures
included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated and combined finaff
ncial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated and combined finaff
ncial statements. We believe that our audits
provide a reasonable basis for our opinion.
We have served as the Company’s auditor since 2013.
Austin, Texas
r
February
25, 2021
F-2
BRIGHAM MINERALS, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
(In thousands, except share data)
Current assets:
Cash and cash equivalents
Accounts receivable
Prepaid expenses and other
Total current assets
Oil and gas properties, at cost, using the full cost method of accounting:
Unevaluated property
Evaluated property
Less accumulated depreciation, depletion, and amortization
Oil and gas properties—net
Other property and equipment
Less accumulated depreciation
Other property and equipment—net
Deferred tax asset
Other assets, net
Total assets
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Total current liabilities
Long-term debt
Other non-current liabilities
Temporary equity
Shareholders' equity:
Preferred stock, $0.01 par value; 50,000,000 authorized; no shares issued and outstanding
at December 31, 2020 and December 31, 2019
Class A common stock, $0.01par value; 400,000,000 authorized, 43,995,124 shares issued
and 43,558,494 shares outstanding at December 31, 2020; 34,040,934 issued and
outstanding at December 31, 2019
Class B common stock, $0.01 par value; 150,000,000 authorized, 13,167,687 shares
issued and outstanding at December 31, 2020; 22,847,045 shares issued and outstanding
at December 31, 2019
Additional paid-in capital
Accumulated deficit
Treasury stock, at cost; 436,630 shares at December 31, 2020 and no shares at
December 31, 2019
Total shareholders' equity attributable to Brigham Minerals, Inc.
December 31,
2020
2019
$
9,144
$
17,632
3,693
30,469
325,091
488,301
(189,546)
623,846
5,587
(4,632)
955
24,920
771
51,133
30,291
1,688
83,112
291,664
449,061
(61,103)
679,622
5,095
(3,703)
1,392
18,823
1,213
680,961
$
784,162
$
$
7,905
$
7,905
20,000
1,126
146,280
—
440
—
601,129
(92,392)
(3,527)
505,650
11,533
11,533
—
803
454,507
—
340
—
323,578
(6,599)
—
317,319
784,162
Total liabilities, temporary equity and shareholders' equity
$
680,961
$
The accompanying notes are an integral part of these consolidated and combined finff ancial statements.
F-3
BRIGHAM MINERALS, INC.
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIRR
ONS
(In thousands, except per share data)
REVENUES
Mineral and royalty revenues
Lease bonus and other revenues
Total revenues
OPERATING EXPENSES
Gathering, transportation and marketing
Severance and ad valorem taxes
Depreciation, depletion, and amortization
Impairment of oil and gas properties
General and administrative
Total operating expenses
(LOSS) INCOME FROM OPERATIONS
(Loss) gain on derivative instruments, net
Interest expense, net
Loss on extinguishment of debt
Gain on sale and distribution of equity securities
Other income, net
(Loss) income before income tax expense
Income tax (benefit) expense
NET (LOSS) INCOME
Less: Net income attributable to Predecessor
Less: net loss (income) attributable to temporary equity
Net (loss) income attributable to Brigham Minerals, Inc. shareholders
NET (LOSS) INCOME PER COMMON SHARE
Basic
Diluted
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic
Diluted
Years Ended December 31,
2019
2018
2020
$
$
$
$
$
$
$
$
$
86,245
5,478
91,723
$
$
97,886
3,629
101,515
$
$
6,985
5,606
48,238
79,569
21,619
162,017
$
(70,294) $
—
(890)
—
—
428
(70,756) $
(12,762)
(57,994) $
—
15,582
(42,412) $
(1.11) $
(1.11) $
38,178
38,178
4,985
6,409
30,940
—
21,963
64,297
37,218
(568)
(5,609)
(6,892)
—
169
24,318
2,679
21,639
(5,092)
(9,646)
6,901
0.26
0.26
22,870
22,870
$
$
$
$
$
$
$
59,758
7,506
67,264
3,944
3,536
13,915
—
6,638
28,033
39,231
424
(7,446)
—
823
110
33,142
327
32,815
(30,976)
—
1,839
—
—
—
—
The accompanying notes are an integral part of these consolidated and combined finff ancial statements.
F-4
BRIGHAM MINERALS, INC.
CONSOLIDATED AND COMBINED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
NET (LOSS) INCOME
Other comprehensive income
Unrealized gains on available for sale equity securities, net
Reclassification of gains on sale and distribution of available for sale equity securities
Other comprehensive loss
COMPREHENSIVE (LOSS) INCOME
Comprehensive income attributable to Predecessor
Comprehensive loss (income) attributable to temporary equity
Years Ended December 31,
2020
2019
2018
$ (57,994) $
21,639
$
32,815
—
—
—
—
—
—
141
(823)
(682)
$ (57,994) $
21,639
$
32,133
$
$
— $
(5,092) $
(30,294)
15,582
$
(9,646) $
—
Comprehensive (loss) income attributable to shareholders
$ (42,412) $
6,901
$
1,839
The accompanying notes are an integral part of these consolidated and combined finff ancial statements.
F-5
BRIGHAM MINERALS, INC.
CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN SHAREHOLDERS' AND MEMBERS’ EQUITY
(In thousands)
Members'
Contributed
Capital
Class A Common
Stock
Class B Common
Stock
Shares
Amount
Shares
Amount
Additional
Paid-In
Capital
Accumulated
Other
Comprehensive
Income
Retained
Earnings
(accumulated
deficit)
Total
Shareholders'
and Members'
Equity
Balance - December 31, 2017
$
166,030
— $
Contributions
Distributions
Other comprehensive
income
Deferred tax liability
arising from corporate
reorganization
Proceeds from sale of
equity securities
Net income attributable to
shareholders
Net income attributable to
predecessor
45,078
(3,313)
—
—
933
—
—
—
—
—
—
—
—
—
Balance - December 31, 2018
$
208,728
— $
Net income attributable to
shareholders
Net income attributable to
Predecessor
Balance prior to corporate
reorganization and IPO
—
—
—
—
$
208,728
— $
—
—
—
—
—
—
—
—
—
—
—
—
— $
— $
— $
682
$
135,462
$
302,174
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(3,057)
—
—
—
—
—
(682)
—
—
—
—
—
—
—
—
—
1,839
45,078
(3,313)
(682)
(3,057)
933
1,839
30,976
30,976
— $
— $
(3,057) $
— $
168,277
$
373,948
—
—
—
—
—
—
—
—
848
5,092
848
5,092
— $
— $
(3,057) $
— $
174,217
$
379,888
Conversion of PE Units for
Class A Common Stock
and Class B Common
Stock
Issuance of common stock
in IPO, net of offering cost
Deferred tax asset arising
from the IPO
Reclassification of
noncontrolling interests to
temporary equity
Issuance of common stock
upon vesting of RSUs, net
of shares withheld for
income taxes
Share-based compensation
expense
Dividends declared
Dividend equivalent rights
declared
Net income attributable to
shareholders
Adjustment of temporary
equity to redemption
amount
Issuance of common stock
in the December 2019
Offering, net of offering
costs
Deferred tax asset arising
from issuance of common
stock in the December 2019
Offering
Conversion of shares of
Class B Common Stock to
Class A Common Stock
Restricted stock forfeited
(208,728)
5,322
53
28,778
— 16,675
167
—
—
—
—
—
—
—
—
—
—
124
—
—
—
—
—
—
6,000
—
—
—
—
5,931
(11)
—
—
1
—
—
—
—
—
60
—
59
—
—
—
—
—
—
—
—
—
—
—
—
(5,931)
—
—
—
—
380,205
273,281
13,664
— (518,000)
—
—
—
—
—
(1,256)
13,888
—
—
—
—
(51,572)
—
102,620
—
—
—
9,508
104,331
(34)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(171,530)
—
—
—
—
—
—
(14,663)
(676)
6,053
—
—
—
—
—
273,448
13,664
(518,000)
(1,255)
13,888
(14,663)
(676)
6,053
(51,572)
102,680
9,508
104,390
(34)
Balance - December 31, 2019
$
— 34,041
$
340
22,847
$
— $ 323,578
$
— $
(6,599) $
317,319
The accompanying notes are an integral part of these consolidated and combined finff ancial statements.
F-6
BRIGHAM MINERALS, INC.
CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN SHAREHOLDERS' AND MEMBERS’ EQUITY
(CONTINUED)
(In thousands)
Shares
Amount
Shares
Amount
Class A
Common Stock
Class B
Common Stock
Additional
Paid-In
Capital
Accumulated
Deficit
Treasury Stock
Shares
Amount
Total
Shareholders'
Equity
Balance - December 31, 2019
34,041
$
340
22,847
$
— $ 323,578
$
(6,599)
— $
— $
317,319
Issuance of common stock upon
vesting of RSUs, net of shares
withheld for income taxes
Shares surrendered for tax
withholdings on vested equity
awards
Conversion of shares of Class B
Common Stock to Class A
Common Stock
Reduction in deferred tax asset
arising from conversion of shares
of Class B Common Stock to
Class A Common Stock
Purchase of treasury stock
Share-based compensation
Restricted stock forfeitures
Dividends declared
Dividend equivalent rights
declared
Net loss attributable to
shareholders
Adjustment of temporary equity to
redemption value
304
(19)
2
—
—
—
9,679
98
(9,679)
—
(437)
—
(10)
—
—
—
—
—
—
—
—
—
—
—
—
440
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(993)
(185)
97,393
(2,640)
—
13,615
—
—
—
—
—
—
—
—
—
—
—
(41,601)
(1,780)
(42,412)
170,361
—
—
—
—
—
437
—
—
—
—
—
—
—
—
—
—
(3,527)
—
—
—
—
—
—
(991)
(185)
97,491
(2,640)
(3,527)
13,615
—
(41,601)
(1,780)
(42,412)
170,361
505,650
Balance - December 31, 2020
43,558
$
13,168
$
— $ 601,129
$
(92,392)
437
$ (3,527) $
The accompanying notes are an integral part of these consolidated and combined finff ancial statements.
F-7
BRIGHAM MINERALS, INC.
CONSOLIDATED AND COMBINED STATEMENT OF CASH FLOWS
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income
Adjustments to reconcile net earnings to net cash provided by operating activities:
Years Ended December 31,
2019
2020
2018
$
(57,994) $
21,639
$
32,815
Depreciation and amortization
Impairment of oil and gas properties
Share-based compensation expense
Loss on extinguishment of debt
Amortization of debt issue costs
Deferred income tax (benefit)/expense
Loss (gain) on derivative instruments, net
Net cash received (paid) for derivative settlements
Gain on sale and distribution of equity securities
Bad debt expense
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivables
(Increase) decrease in other current assets
Decrease in other deferred charges
(Decrease) increase in accounts payables and accrued liabilities
Increase in other long-term liabilities
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties
Additions to other fixed assets
Proceeds from sale of oil and gas properties, net
Proceeds from sale of equity securities
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Payments of short-term related party loan
Borrowing of short-term related party loan
Payments of short-term debt
Payments of long-term debt
Borrowing of long-term debt
Payment of debt extinguishment fees
Proceeds from issuance of Class A common stock sold in initial public offering,
net of offering costs
Proceeds from issuance of Class A common stock, net of offering costs
Capital contributions
Capital distributions
Purchase of treasury stock
Dividends paid
Distributions to holders of temporary equity
Debt issuance cost
Employee tax withholding for settlement of equity compensation awards
Net cash (used in) provided by financing activities
(Decrease) increase in cash and cash equivalents and restricted cash
Cash, cash equivalents and restricted cash, beginning of period
Cash, cash equivalents and restricted cash end of period
48,238
79,569
7,529
—
605
(9,942)
—
—
—
299
12,359
(2,005)
45
(3,608)
165
75,260
$
30,940
—
10,049
6,892
433
665
568
470
—
669
(10,246)
1,787
—
5,112
47
69,025
(66,498)
(492)
1,565
—
(65,425) $
(219,481)
(474)
3,123
—
(216,832) $
—
—
—
—
20,000
—
—
—
—
—
(3,527)
(42,216)
(24,670)
(208)
(1,203)
(51,824) $
(41,989)
51,133
9,144
$
—
—
(4,596)
(275,404)
105,000
(2,091)
277,075
102,680
—
(441)
—
(14,663)
(19,731)
(1,348)
—
166,481
18,674
32,459
51,133
$
$
13,915
—
—
—
690
237
(424)
(754)
(823)
382
(8,022)
(6,116)
—
(484)
28
$31,444
(195,603)
(723)
125
933
(195,268)
(7,000)
7,000
—
(70,000)
218,000
—
—
—
46,011
—
—
—
—
(4,614)
—
189,397
25,573
6,886
32,459
$
$
$
$
The accompanying notes are an integral part of these consolidated and combined finff ancial statements.
F-8
BRIGHAM MINERALS, INC.
CONSOLIDATED AND COMBINED STATEMENT OF CASH FLOWS
(CONTINUED)
(In thousands)
Supplemental disclosure of non-cash activity:
Equity securities distributed
Accrued capital expenditures
Capitalized share-based compensation cost
Temporary equity cumulative adjustment to fair value
Supplemental cash flow information:
Cash (payments) for loan commitment fees and interest
Cash received/(paid) for taxes
Years Ended December 31,
2019
2020
2018
$
$
— $
146
— $
63
6,086
(170,361)
3,818
51,572
3,313
1,426
—
—
(715) $
1,211
(6,192) $
(832)
(6,123)
(604)
The accompanying notes are an integral part of these consolidated and combined finff ancial statements.
F-9
BRIGHAM MINERARR LS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
1.
Business and Basis of Presentation
Description of the Business
Brigham Minerals, Inc. (together with its wholly owned subsidiaries, “Brigham Minerals” or the “Company”) is a
Delaware corporation formed in June 2018 to become a holding company. Brigham Minerals acquired an indirect interest in
Brigham Resources, LLC (“Brigham Resources”), our predecessor, on July 16, 2018 in a series of restructuring transactions
Pincus LLC (“Warburg Pincus”) contributed all of their respective
pursuant to which certain entities affiliated with Warburg
interests in the entities through which they held interests in Brigham Resources to Brigham Minerals in exchange for all of the
outstanding shares of common stock of Brigham Minerals (the “July 2018 restructuring”
). As a result of such restructuring
transactions, Brigham Minerals became wholly owned by an entity affiliated with Warburg Pincus, and Brigham Minerals
indirectly owned a 16.5% membership interest in Brigham Resources. The remaining outstanding membership interests of
Brigham Resources remained with certain other entities affiliated with Warburg
Pincus, Yorktown Partners LLC and Pine
Brook Road Advisors, LP, Brigham Minerals’ management and its other investors (collectively, the “Original Owners”).
r
r
t
On November 20, 2018, Brigham Resources underwent a second series of restructuring transactions (the “November
2018 restructuring”). In the November 2018 restructuring, Brigham Resources became a wholly owned subsidiary of Brigham
Minerals Holdings, LLC (“Brigham LLC”), which was a wholly owned subsidiary of Brigham Equity Holdings, LLC
(“Brigham Equity Holdings”), and Brigham Equity Holdings became wholly owned by the owners of Brigham Resources
immediately prior to such restructuring, directly or indirectly, through Brigham Minerals. As a result of the foregoing
transactions, there was no change in the control or economic interests of the Original Owners and Brigham Minerals in Brigham
Resources, although their ownership became indirect through Brigham Equity Holdings and its wholly owned subsidiary,
Brigham LLC. The July 2018 restructuring and the November 2018 restructuring are collectively referred to herein as the “2018
corporate reorganizations.”
Brigham Resources wholly owns Brigham Minerals, LLC and Rearden Minerals, LLC (collectively, the “Minerals
Subsidiaries”), which acquire and actively manage a portfolio of mineral and royalty interests. The Minerals Subsidiaries are
Brigham Resources’ sole material assets.
Initial Public Offering
ff
In April 2019, Brigham Minerals completed its' initial public offering (the "IPO") of 16,675,000 shares of Class A common
stock at a price to the public of $18.00 per share. This resulted in net proceeds of approximately $273.4 million, after deducting
underwriting commissions and discounts and offering expenses, which proceeds were used to repay $200.0 million of existing
indebtedness and to fund mineral and royalty acquisitions. As a result of the IPO and the corporate restructuring described in
"Note 9—Temporary Equity", Brigham Minerals became a holding company whose sole material asset consisted of a 43.3%
interest in Brigham LLC, which wholly owns Brigham Resources. Brigham Resources continues to wholly own the Minerals
ries, which own all of Brigham Resources’ operating assets. In connection with the IPO, Brigham Minerals became the
Subsidia
sole managing member of Brigham LLC and is responsible for all operational, management and administrative decisions
relating to Brigham LLC’s business and consolidates the financial results of Brigham LLC and its wholly owned subsidiary,
Brigham Resources.
u
December 2019 Offeff ring
On December 16, 2019, Brigham Minerals completed an offering of 12,650,000 shares of its Class A common stock (the
"December 2019 Offering"), including 6,000,000 shares issued and sold by Brigham Minerals and an aggregate of 6,650,000
shares sold by certain shareholders of the Company (the "Selling Shareholders"), of which 5,496,813 represents shares issued
upon redemption of an equivalent number of their Brigham LLC units, at a price to the public of $18.10 per share ($17.376 per
share net of underwriting discounts and commissions). After deducting underwriting discounts, commissions and offering
expenses, Brigham Minerals received net proceeds of approximately $102.7 million which were used to repay $80.0 million of
existing indebtedness under our revolving credit agreement and will be used to fund future mineral and royalty acquisitions.
Brigham Minerals did not receive any proceeds from the sale of shares of Class A common stock by the Selling Shareholders.
June 2020 Secondary Offeff ring
On June 12, 2020, Brigham Minerals completed an offering of 6,600,000 shares of its Class A common stock (the "June
2020 Secondary Offering"), all of which were sold by certain shareholders of the Company (the “June 2020 Selling
F-10
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Shareholders”), and 4,872,669 of which represented shares issued upon redemption of an equivalent number of the June 2020
Selling Shareholders’ Brigham LLC Units (together with a corresponding number of shares of Class B common stock in
Brigham Minerals), at a price to the public of $13.75 per share. Brigham Minerals did not sell any shares of its common stock
in the June 2020 Secondary Offeri
ng and did not receive any proceeds pursuant to the June 2020 Secondary Offering.
ff
September 2020 Secondary Offeff ring
On September 15, 2020, Brigham Minerals completed an offering of 5,021,140 shares of its Class A common stock,
including 654,931 shares issued pursuant to the option granted to the underwriter to purchase additional shares to cover over-
allotments (the "September 2020 Secondary Offering"), all of which were sold by certain shareholders of the Company (the
"September 2020 Selling Shareholders"), and 3,062,011 of which represented shares issued upon redemption of an equivalent
number of the September 2020 Selling Shareholders’ Brigham LLC Units (together with a corresponding number of shares of
Class B common stock in Brigham Minerals), at a price to the public of $8.20 per share. Brigham Minerals did not sell any
shares of its Class A common stock in the September 2020 Secondary Offering and did not receive any proceeds pursuant to the
September 2020 Secondary Offering. In addition, in connection with the September 2020 Secondary Offering, Brigham
Minerals repurchased 436,630 shares of its Class A common stock from the September 2020 Selling Shareholders in a privately
negotiated transaction at a price equal to the price per share at which the underwriter purchased shares from the September 2020
Selling Shareholders in the September 2020 Secondary Offering (and Brigham LLC redeemed a corresponding number of
Brigham LLC Units held by Brigham Minerals). The repurchased shares are presented in the Company's consolidated balance
sheet as Treasury Stock, at cost.
Following the completion of the September 2020 Secondary Offering and as of December 31, 2020, Brigham Minerals
owned a 76.8% interest in Brigham LLC and the Original Owners owned 23.2% of the outstanding voting stock of Brigham
Minerals. Certain other entities affiliated with Yorktown Partners LLC and Pine Brook Road Advisors, LP, which are a subset
of the Company's Original Owners, collectively owned 16.9% of the outstanding voting stock of Brigham Minerals as of
December 31, 2020.
Basis of Presentation
Subsequent to the July 2018 restructuring and prior to the IPO, Brigham Minerals used the equity method of accounting
for its investment in Brigham Resources, its predecessor, because its 16.5% ownership in Brigham Resources provided
Brigham Minerals with significant influence, but not with a controlling financial interest or the ability to direct the most
significant activities of Brigham Resources. Upon the completion of the IPO, Brigham Minerals indirectly owned an
approximate 43.3% interest of Brigham Resources and 100% of the voting rights and consolidates the results of operations of
Brigham Resources. In order to furnish comparative financial information, the accompanying consolidated and combined
financial statements and related notes of Brigham Minerals for periods prior to the IPO have been retrospectively recast to
ncial information of both Brigham Resources (at historical carrying values) and Brigham
include the combined historical finaff
ral income taxes and liabilities associated with Brigham Minerals. All intercompany
Minerals, taking into account state and fede
transactions between Brigham Minerals and Brigham Resources have been eliminated. Because Brigham Minerals acquired an
interest in Brigham Resources as part of the 2018 corporate reorganization, net income is attributablea
to stockholders of
Brigham Minerals in addition to our Predecessor beginning in 2018.
ff
The accompanying consolidated and combined finaff
ncial statements of Brigham Minerals have been prepared in
accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated and
combined finaff
all normal recurring adjustments that, in the opinion of management, are necessary for a
fair representation. Brigham Minerals operates in one segment: oil and natural gas exploration and production.
ncial statements reflect
ff
2.
Significant Accounting Policies
Emerging Growth Company Status
As a company with less than $1.07 billion in revenues during its last fisff cal year, Brigham Minerals qualifies as an
“emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). An emerging
growth company may take advantage of specified reduced reporting and other regulatory requirements.
F-11
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Brigham Minerals will remain an “emerging growth company” until as late as the last day of Brigham Minerals’ 2023
fiscal year, or until the earliest of (i) the last day of the fiscal year in which Brigham Minerals has $1.07 billion or more in
annual revenues; (ii) the date on which Brigham Minerals becomes a “large accelerated filer” (the fiscal year-end on which the
total market value of Brigham Minerals’ common equity securities held by non-affiliates is $700 million or more as of June 30);
(iii) the date on which Brigham Minerals issues more than $1.0 billion of non-convertible debt over a three-year period.
As a result of Brigham Minerals’ election to avail itself of certain provisions of the JOBS Act, the information that
Brigham Minerals provides may be differe
ff
nt than the information provided by other public companies.
Use of Estimates
The preparation of consolidated and combined finaff
ncial statements in conformity with GAAP requires management to
make estimates and assumptim ons that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure
ncial statements and accompanying notes. Although
of contingent assets and liabilities in the consolidated and combined finaff
management believes these estimates are reasonable, actual results could differ fromff
these estimates. Changes in estimates are
recorded prospectively.
The accompanying consolidated and combined finaff
ncial statements are based on a number of significant estimates
gas and NGLs reserves that are the basis for the calculations of depreciation, depletion,
t
including quantities of oil, natural
gas properties. Reservoir engineering is a subjective process of
amortization (“DD&A”) and impairment of oil and natural
gas and there are numerous uncertainties inherent in estimating
estimating underground accumulations of oil and natural
ion of the quality of available
ff
quantities of proved oil and natural
from the quantities
data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differff
of oil and natural
gas that are ultimately recovered. Brigham Minerals’ reserve estimates are audited by Cawley, Gillespie &
Associates, Inc. (“CG&A”), an independent petroleum engineering firm. Other items subject to significant estimates and
assumptim ons include the carrying amount of oil and natural
gas properties, valuation of derivative instruments, share-based
r
compensation and revenue accrual
gas reserves. The accuracy of any reserve estimate is a funct
s.
t
t
t
t
t
Cash and Cash Equivalents
Brigham Minerals considers all highly liquid investments with an original maturity of three months or less to be cash
equivalents.
Receivables
Receivables consist of royalty income due from operators for oil and gas sales to purchasers. Those purchasers remit
payment for production to the operator of our properties and the operator, in turn, remits payment to us. Receivables from third
to timing delays or due to the unavailability of data at the
parties forff which we did not receive actual information, either dued
l data are based
time when revenues are recognized, are estimated. Volume estimates for wells with available historical actuat
the months the historical
upon (i) the historical actual data forff
actual data is not available. We do not recognize revenues for wells with no historical actuat
l data because we cannot conclude
that it is probable that a significant revenue reversal will not occur in future periods. Pricing estimates are based upon actual
the average basis differential from market on a basin-by-basin basis.
prices realized in an area by adjusting the market price forff
, or (ii) engineering estimates forff
the months the data is availablea
Brigham Minerals routinely reviews outstanding balances, assesses the financial strength of its customers and records a
reserve for amounts not expected to be fully recovered. We recorded an allowance forff
doubtful accounts of $0.3 million and
$0.6 million for the year ended December 31, 2020 and 2019, respectively, which was included in general and administrative
expenses.
At December 31, 2020 and 2019, accounts receivable was comprised of the folff
lowing:
(In thousands)
Oil and gas sales
Allowance for doubtful accounts
Other
Total accounts receivables
December 31,
2020
2019
$
$
17,413
$
(855)
1,074
17,632
$
27,888
(556)
2,959
30,291
F-12
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
BRIGHAM MINERALSRR
, INC.
Concentration of Credit Risk and Significant Customers
Financial instruments that potentially subject Brigham Minerals to concentrations of credit risk consist of cash, accounts
receivable, commodity derivative financial instruments and our revolving credit facility. Cash and cash equivalents are held in a
ons in amounts that may, at times, exceed federally insured limits. However, no losses have been incurred
few financial instituti
and management believes that counterparty risks are minimal based on the reputation and history of the instituti
ons selected.
Accounts receivable are concentrated among operators and purchasers engaged in the energy industry within the United States.
Management periodically assesses the financial condition of these entities and institutions and considers any possible credit risk
to be minimal. Concentrations of oil and gas sales to significant customers (operators) are presented in the tabla e below.
t
t
Occidental Petroleum Corp.
Royal Dutch Shell
Exxon Mobil Corp.
Continental Resources, Inc.
For the year ended December 31,
2020
2019
2018
12 %
12 %
11 %
10 %
16 %
— %
10 %
12 %
15 %
— %
— %
10 %
Management does not believe that the loss of any customer would have a long-term material adverse effect on our
financial position or the results of operations.
Investments in Equity Securities
In January 2019, the Company adopted ASU 2016-01, Financial Instrume
nts-Overall: Recognition and Measurement of
Financial Assets and Financial Liabilities. The ASU changes to the current GAAP model primarily affect the accounting for
equity investments, financial liabilities under the fair value option and the presentation and disclosure requirements forff
financial
instruments. Under the new standard, all equity investments in unconsolidated entities (other than those accounted for using the
equity method of accounting) will generally be measured at fair value through earnings. There will no longer be an available-
for-sale classification (changes in fair value reported in other comprehensive income) for equity securities with readily
determinablea
fair values.
rr
ff
value. Changes in faiff
Prior to January 2019, Brigham Minerals classified its equity securities as available-for-sale, and as such, they were
carried at fair
r value of available-for-sale securities were reported as a component of other comprehensive
income. Losses were recognized within the consolidated and combined statement of operations when a decline in value is
determined to be other-than-temporary. Brigham Minerals used the average cost method to determine the realized gain or loss
for each sale or distribution of availablea
-for-sale securities.
Financial Instruments
Brigham Minerals’ financial instruments consist of cash and cash equivalents, receivables, payablea
s, derivative assets and
liabilities, investments in equity securities and long-term debt. The carrying amounts of cash and cash equivalents, receivables
and payables approximate fair value due to the highly liquid or short-term nature of these instruments.
The fair values of Brigham Minerals’ derivative assets and liabilities are based on a third-party industry-standard pricing
model using contract terms and prices and assumptim ons and inputs that are substantially observable in active markets throughout
the full term of the instruments, including forward oil and gas price curves, discount rates, volatility factors and credit risk
adjustments.
The carrying amount of long-term debt associated with borrowings outstanding under Brigham Minerals’ revolving credit
r value as borrowings bear interest at variable market rates. See “Note 5—Derivative Instruments,”
mates faiff
facility approxi
a
“Note 6—Fair Value Measurements” and “Note 7—Long-Term Debt.”
F-13
BRIGHAM MINERARR LS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Oil and Gas Properties
Brigham Minerals uses the full cost method of accounting for its oil and natural
gas properties. Under this method, all
acquisition costs incurred for the purpose of acquiring mineral and royalty interests and certain related employee costs are
capita
cost pool. Costs associated with general corporate activities are expensed in the period incurred.
alized into a full
ff
t
Capita
alized costs are amortized using the units-of-production method. Under this method, the provision for depletion is
calculated by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the
total unamortized cost base by net equivalent proved reserves at the beginning of the period.
Costs associated with unevaluated properties are excluded from the amortizable cost base until a determination has been
made as to the existence of proved reserves. Unevaluated properties are reviewed periodically to determine whether the costs
incurred should be reclassified to the full cost pool and subjected to amortization. The costs associated with unevaluated
alized general and administrative costs. Unevaluated properties are
properties primarily consist of acquisition costs and capita
assessed for impairment on an individual basis or as a group if properties are individually insignificant. The assessment
includes consideration of the following factors, among others: expectation of future drilling activity; past drilling results and
activity; geological and geophysical evaluations; the assignment of proved reserves; and the economic viabila
ity of development
if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative acquisition
such property are transferred to the full cost pool and are then subject to amortization. There was no
costs incurred to date forff
unevaluated properties in 2020, 2019 and 2018.
impairment recorded forff
Sales and abandonments of oil and natural
as adjustments to the full cost
pool, with no gain or loss recognized unless the adjustments would significantly alter the relationship between capita
alized costs
and proved reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less
than 25% of the reserve quantities of a cost center.
gas properties being amortized are accounted forff
t
Natural gas volumes are converted to barrels of oil equivalent (Boe) at the rate of six thousand cubic feeff
t (Mcf) of natural
gas to one barrel (Bbl) of oil. This convention is not an equivalent price basis and there may be a large difference in value
between an equivalent volume of oil versus an equivalent volume of naturat
l gas.
t
t
alized costs of oil and natural
Under the full cost method of accounting, total capita
gas properties, net of accumulated
depletion and related deferred income taxes, may not exceed an amount equal to the present value of future net revenues fromff
proved reserves, discounted at 10% per annum ("PV-10"), plus the cost of unevaluated properties less related income tax effects
(the ceiling limitation). A ceiling limitation is calculated at each reporting period. If total capita
alized costs, net of accumulated
DD&A and related deferred income taxes are greater than the ceiling limitation, a write-down or impairment of the full cost
pool is required. A write-down of the carrying value of the full cost pool is a noncash charge that reduces earnings and impacts
equity in the period of occurrence and typically results in lower depletion expense in future periods. Once incurred, a write-
down cannot be reversed at a later date. The ceiling limitation calculation is prepared using an unweighted arithmetic average of
oil prices ("SEC oil price") and natural
the trailing 12-month
energy content, transportation fees and regional price differentials, as
period ended December 31, 2020, adjusted by area forff
icable, these net wellhead prices would be further adjusted to
required under the guidelines established by the SEC. If appl
include the effects of any fixed price arrangements forff
gas. For the year ended December 31, 2020, as
a result of its quarterly full
cost ceiling analysis, Brigham Minerals recorded impairments of proved oil and gas properties of
$79.6 million, due to declines in the 12-month average realized price of crude oil, as well as reclassificff ation of proved
undeveloped reserves to probable and possible reserves, as a result of a slowdown in operator activity. See “Note 3—Oil and
Gas Properties” for further discussion.
gas prices ("SEC gas price") as of the first day of each month forff
the sale of oil and natural
a
ff
t
t
Share-Based Compensation
Brigham Minerals accounts for its share-based compensation including grants of the Incentive Units (as hereinafter
defined), restricted stock awards, time-based restricted stock units and performance-based stock units in the consolidated and
combined statements of operations based on their estimated faiff
r values at grant date. Brigham Minerals uses a Monte Carlo
simulation to determine the fair value of performance-based stock units. Brigham Minerals recognizes expense on a straight-
line basis over the vesting period of the respective grant, which is generally the requisite service period. Brigham Minerals
capita
alizes a portion of the share-based compensation cost to oil and gas properties on the consolidated balance sheets. Share-
based compensation expense is included in general and administrative expenses in Brigham Minerals’ consolidated and
combined statements of operations included within this Annual Report. There was approximately $17.0 million of unamortized
compensation expense relating to outstanding awards at December 31, 2020, a portion of which will be capia talized. The
F-14
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
unrecognized share-based compensation expense will be recognized on a straight-line basis over the remaining vesting periods
as they occur.
of the awards. Brigham Minerals accounts forff
t
forfeitures
Earnings Per Share
Brigham Minerals uses the “if-converted” method to determine the potential dilutive effecff
t of its Class B common stock
and the treasury stock method to determine the potential dilutive effect of outstanding Incentive Units, RSAs, RSUs, and PSUs.
Employee Benefit Plan
We sponsor a 401(k) tax-deferred savings plan forff
our employees. We match 100% of each employee’s contributions, up
to 6% of the employee’s total compensation. Brigham Resources may also contribute additional amounts at its discretion.
Brigham Resources contributed $0.4 million, $0.3 million and $0.2 million, to the 401(k) plan forff
each of the years ended
December 31, 2020, 2019, and 2018.
Income Taxes
Brigham Minerals accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are
recognized for the future tax consequences attributablea
to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing
tax laws and the rates expected to appl
y to taxable income in the years in which those temporary differences are expected to be
recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the
period that includes the enactment date.
a
Brigham Minerals periodically assesses whether it is more likely than not that it will generate sufficient taxable income to
realize its deferred income tax assets, including net operating losses. In making this determination, Brigham Minerals considers
all available positive and negative evidence and makes certain assumptim ons. Brigham Minerals considers, among other things,
its deferred tax liabia lities, the overall business environment, its historical earnings and losses, current industry trends and its
outlook for future years.
Temporary Equity
Brigham Minerals accounts for the Original Owners’ 23.2% interest in Brigham LLC as of December 31, 2020, as
temporary equity as a result of certain redemption rights held by the Original Owners as discussed in “Note 9—Temporary
Equity.” As such, the Company adjusts temporary equity to its maximum redemption amount at the balance sheet date, if higher
than the carrying amount. The redemption amount is based on the 10-day volume-weighted average closing price (“VWAP”) of
Class A shares at the end of the reporting period. Changes in the redemption value are recognized immediately as they occur, as
if the end of the reporting period was also the redemption date forff
the instrument, with an offsetting entry to additional paid-in
capita
al. Temporary equity is reclassifieff d to permanent equity (i) upon Conversion of Class B common stock (and an equivalent
number of Brigham LLC Units) to Class A common stock, or (ii) when holders of Class B common stock no longer control a
ty of the votes of the board of directors through direct representation on the board of directors, and no longer control the
a
majori
determination of whether to make a cash payment upon a Brigham Unit Holder's exercise of its Redemption Right.
Revenue from Contracts with Customers
In 2019, the Company adopted Accounting Standards Codification Topic 606, Revenue from Contracts with Customers,
("ASC 606") using the modified retrospective approach, which only applied to contracts that were in effect as of the date of
adoption. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and did
not impact the Company’s previously reported results of operations, nor its ongoing consolidated balance sheets, consolidated
or statements of changes in shareholders' and members' equity. Overall, there were no
and combined statements of cash flowff
material changes in the timing of the satisfaction of the Company’s performance obligations or the allocation of the transaction
price to its performance obligations in applying the guidance in ASC 606 as comparem
d to legacy U.S. GAAP.
Oil and natural gas sales
Oil, natural gas and NGLs sales revenues are generally recognized when control of the product is transferred to the
customer, the performa
ity is
reasonably assured. All of the Company’s oil, natural gas and NGL sales are made under contracts with customers (operators).
f
The perforff mance obligations for the Company’s contracts with customers are satisfied at a point in time through the delivery orr
oil and natural gas to its customers. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. The
nce obligations under the terms of the contracts with customers are satisfied and collectabila
ff
F-15
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
BRIGHAM MINERALSRR
, INC.
t
gas and NGL sales within 60 days of the month of delivery, which can
Company typically receives payment for oil, natural
extend up to 9 months after initial production from the well. The Company’s contracts forff
gas and NGL sales are
standard industry contracts that include variable consideration based on the monthly index price and adjustments that may
include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions.
As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and
natural
gas sales using the allocation exception for
t
variable consideration in ASC 606.
gas prices, Brigham Minerals recognizes revenue from oil and natural
oil, natural
t
t
Lease bonus and other
tt
income
Brigham Minerals also earns revenue from lease bonuses, delay rentals, and right-of-way payments. We generate lease
bonus revenue by leasing our mineral interests to exploration and production companies. A lease agreement represents our
contract with a customer and generally transfers the rights to any oil or natural
gas discovered, grants us a right to a specified
royalty interest, and requires that drilling and completion operations commence within a specified time period. The Company
recognizes lease bonus revenues when the lease agreement has been executed, payment has been received, and the Company
has no further obligation to refund the payment. At the time Brigham Minerals executes the lease agreement, Brigham Minerals
expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that Brigham
Minerals has not adjusted the expected amount of consideration for the effects of any significant financing component per the
practical expedient in ASC 606. Brigham Minerals also recognizes revenue from delay rentals to the extent drilling has not
started within the specified period, payment has been received, and we have no further obligation to refund the payment. Right-
of-way payments are recorded by the Company when the agreement has been executed, payment is determined to be
collectable, and the Company has no further obligation to refund the payment.
t
Allocll ationtt
of transaction price to remaining pn
tt
erformance obligat
ions
ll
Oil and natural gas sales
Brigham Minerals’ right to royalty income does not originate until production occurs and, therefore, is not considered to
exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of our royalty income
contracts.
Lease bonus and other income
Given that Brigham Minerals does not recognize lease bonus or other income until a lease agreement has been executed,
at which point its performance obligation has been satisfied, and payment is received, Brigham Minerals does not record
revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.
Prior-period
rr
tt
performance obligat
ions
ll
Brigham Minerals records revenue in the month production is delivered to the purchaser. As a non-operator, Brigham
Minerals has limited visibility into the timing of when new wells start producing and production statements may not be received
for 30 to 90 days or more after the date production is delivered. As a result, Brigham Minerals is required to estimate the
amount of production delivered to the purchaser and the price that will be received forff
the sale of the product. The expected
sales volumes and prices for these properties are estimated and recorded within the accounts receivable line item in the
between the Company’s estimates and the actual amounts received
accompanying consolidated balance sheets. The difference
for oil and natural
is received from the third party. For the years
ended December 31, 2020, 2019 and 2018, revenue recognized in the reporting periods related to performance obligations
satisfied in prior reporting periods was immaterial.
gas sales is recorded in the month that payment
ff
t
Debt Issuance Cost
Other assets include capita
alized debt issuance costs of $0.8 million, net of accumulated amortization of $0.8 million as of
December 31, 2020. As of December 31, 2019, capita
alized debt issuance costs of $1.2 million, net of accumulated amortization
of $0.2 million, was included in long-term debt on the consolidated balance sheets. Debt issuance costs were incurred in
shing and amending credit facilities for Brigham Resources and are amortized over the term of the credit
connection with establia
facilities using the straight-line method, which approximates the effective interest rate method. Amortization expense for debt
issue costs was $0.6 million, $0.4 million and $0.7 million for the years ended December 31, 2020, 2019, and 2018. During the
year ended December 31, 2020, we wrote off debt issuance cost of $0.3 million as a result of the reduction of the borrowing
base on our revolving credit facility that occurred in May 2020. On July 27, 2018, the prior revolving credit facility was
terminated and replaced with the Owl Rock credit facility. On May 16, 2019, the Owl Rock credit facility was terminated and
F-16
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
replaced with a new revolving credit facility. See furff
combined finaff
ncial statements.
ther discussion in "Note 7—Long-Term Debt" in our consolidated and
Recently Issued Accounting Standards Not Yet Adopted
Brigham Minerals’ status as an emerging growth company ("EGC") under Section 107 of the JOBS Act permits it to
delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. Brigham
Minerals is choosing to take advantage of this extended transition period and, as a result, it will comply with new or revised
private companies. If Brigham
accounting standards on the relevant dates on which adoption of such standards is required forff
loses its status as an EGC before the adoption dates for private companies, Brigham Minerals will be required to accelerate the
adoption of new or revised accounting standards.
t
In February 2016, the FASB issued ASU 2016-02, Leases, which requires all leasing arrangements to be presented in the
balance sheet as liabilities along with a corresponding asset. ASU 2016-02 does not apply to leases of mineral rights to explore
for or use crude oil and natural
gas. The ASU will replace most existing lease guidance in GAAP when it becomes effective. In
January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, to provide an
optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases
under Topic 840. In July 2018, the FASB issued ASU 2018-11 Leases (Topic 842): Targeted Improvements, which provides forff
another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases
standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the
period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current
GAAP (Topic 840, Leases)). The new standard becomes effective for us during the fiscal year ending December 31, 2022 and
interim periods within the fiscal year ending December 31, 2023 and early adoption is permitted. We are currently evaluating
the impact that the adoption of this updat
ncial statements and related
disclosures.
e will have on our consolidated and combined finaff
u
In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses. In May 2019, ASU 2016-13 was
subsequently amended by ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses and
ASU 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. ASU 2016-13, as amended,
affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income.
instruments measured at
This ASU will replace the currr ently required incurred loss approach with an expected loss model forff
amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2022, including
interim periods within those fiscal years. ASU 2016-13 will be applied using a modified retrospective approach through a
cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is
e will have on our condensed consolidated and
effective. We are currently evaluating the impact that the adoption of this updat
combined finaff
ncial statements and related disclosures.
u
3.
Oil and Gas Properties
Brigham Minerals uses the full cost method of accounting for its oil and natural
gas properties. Under this method, all
the purpose of acquiring mineral and royalty interests, including certain internal costs, are
cost pool. Costs associated with general corporate activities are expensed in the period incurred. Oil and
ff
t
acquisition costs incurred forff
capita
gas properties consisted of the folff
alized into a full
lowing:
(In thousands)
Oil and gas properties, at cost, using the full cost method of accounting:
Not subject to depletion
Subject to depletion
Total oil and gas properties, at cost
Less accumulated depreciation, depletion, and amortization
Total oil and gas properties, net
December 31,
2020
2019
$
325,091
$
488,301
813,392
(189,546)
291,664
449,061
740,725
(61,103)
$
623,846
$
679,622
Costs not subject to depletion are as follows, by the year in which such costs were incurred:
F-17
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(In thousands)
Property Acquisition costs
Total
$ 325,091
2020
$ 34,032
2019
$ 80,799
2018
$ 72,884
2017
$ 65,925
2016
$ 10,624
Prior
60,827
$
By Year:
Capita
alized costs are depleted on a unit of production basis based on proved oil and natural
gas reserves. Depletion
expense was $47.3 million, $30.4 million and $13.3 million for the year ended December 31, 2020, 2019 and 2018,
respectively. Average depletion of proved properties was $13.63, $11.22 and $9.38 per Boe for the year ended December 31,
2020, 2019 and 2018, respectively.
t
The costs associated with unevaluated properties primarily consist of acquisition costs and capita
alized general and
administrative costs. Brigham Minerals capitalizes certain overhead expenses and other internal costs attributablea
to the
acquisition of mineral and royalty interests as part of its investment in oil and gas properties over the periods benefitted by these
activities. Capitalized costs do not include any costs related to general corporate overhead or similar activities. Capitalized costs
were $10.2 million, $7.4 million and $2.7 million for the years ended December 31, 2020, 2019 and 2018, respectively.
As of December 31, 2020, 2019 and 2018, the SEC oil price and SEC gas price used in the calculation of the ceiling test,
energy content, transportation fees and regional price differentials, were $39.57, $55.65, and $65.66 per
adjusted by area forff
barrel of oil and $2.00, $2.60, and $3.12 per MMbtu ot
gas, respectively. During the year ended December 31, 2020,
Brigham Minerals recorded ceiling test impairment charges of $79.6 million to oil and gas properties, net, as a result of its
quarterly ceiling test analysis. The impairment charges were due to declining SEC oil prices and SEC gas prices, as well as
n of proved undeveloped reserves to probable and possible reserves, as a result of a slowdown in operator
certain reclassificatio
activity. There was no impairment charge during the year ended December 31, 2019 and 2018.
t
f natural
ff
Further decline in the SEC oil price or the SEC gas price could lead to additional impairment charges in the future and
such impairment charges could be material. In addition to the impact of lower prices, any future changes to assumptim ons of
of oil and gas properties, proved undeveloped
drilling and completion activity, development timing, acquisitions or divestitures
locations, and production and other estimates may require revisions to estimates of total proved reserves which would impact
the amount of any impairment charge.
t
During the year ended December 31, 2020, Brigham Minerals reduced its proved undeveloped reserves by 8,209 MBoe
primarily due to a reclassification of 7,036 MBoe from proved undeveloped reserves to probable and possible reserves, as a
result of decreased rig activity, a 29% reduction in SEC oil prices over the twelve months, and conversion from proved
undeveloped to proved developed reserves. The reduction in rig activity led to changes in the development timing and a
reduction of the number of proved undeveloped locations that Brigham Minerals expects will be developed within fiveff
years
after the date of booking.
4.
Acquisitions and Divestitures
In 2019, Brigham Minerals adopted ASU 2017-01, Clarifying the Definition of a Business, using a prospective approach.
This guidance assists in determining whether a transaction should be accounted for as an acquisition of assets or as a business.
This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are
assets, the set will not be considered a business. If
concentrated in a single identifiable asset, or a group of similar identifiablea
the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to
create an output to be considered a business. The adoption of the new standard did not have a material impact on the
consolidated and combined finaff
ncial statements.
During the years ended December 31, 2020 and 2019, Brigham Minerals entered into a number of individually
insignificant acquisitions of mineral and royalty interests from various sellers in Texas, Oklahoma, Colorado, New Mexico,
and North Dakota, as reflected in the tablea
gas property balance is comprised of
payments forff
alized general and administrative expenses that were
funded with borrowings under its Owl Rock credit facff
ility, our revolving credit facility and proceeds from the IPO.
acquisitions of minerals, land brokerage costs and capita
below. The change in the oil and natural
t
(In thousands)
Year ended December 31, 2020
Year ended December 31, 2019
Assets Acquired
Evaluated
30,856
Unevaluated
35,725
$
140,025
$
78,093
$
$
Cash
Consideration
Paid
$
$
66,581
218,118
F-18
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
BRIGHAM MINERALSRR
, INC.
5.
Derivative Instruments
Brigham Minerals periodically uses commodity derivative instrume
nts to reduce its exposure to commodity price
volatility for a portion of its forec
gas sales and thereby achieve a more predictable level of cash
flows. None of the derivative instruments are designated as hedges. Brigham Minerals does not enter into derivative
instruments forff
speculative or trading purposes.
asted crude oil and natural
ff
rr
t
Because the counterparties to Brigham Minerals derivative instruments have investment grade credit ratings, Brigham
its counterparties.
Minerals believes it does not have significant credit risk and does not anticipate nonperformance fromff
Brigham Minerals continually monitors the credit ratings of its counterparties.
Concurrent with the termination of its prior revolving credit facility in July 2018, Brigham Resources posted cash
d price swap contracts. The cash collateral was $1.6 million in May 2019
entering into our revolving
collateral of $1.4 million for its existing WTI fixeff
prior to the termination of the Owl Rock credit facility and was returned
credit facility.
to Brigham Resources uponu
t
Brigham Minerals had no derivative contracts in place as of December 31, 2020 and 2019. Prior to December 31, 2019,
ontracts based on the New York Mercantile Exchange ("NYMEX") futures index.
we had certain oil swap ca
The following tablea
summarizes Brigham Minerals' (loss) gain on derivative instruments, net on its consolidated and
combined statement of operations for the year ended December 31, 2020, 2019 and 2018:
(In thousands)
Realized gain (loss)
Unrealized (loss) gain
(Loss) gain on derivative instruments, net
6.
Fair Value Measurements
Years Ended December 31,
2020
2019
2018
$
$
— $
—
— $
470
$
(1,038)
(568) $
(754)
1,178
424
We classify financial assets and liabia lities that are measured and reported at fair value on a recurring basis using a
hierarchy based on the inputs used in measuring fair value. GAAP defines fair value as the price that would be received to sell
an asset or paid to transfer a liabia lity in an orderly transaction between market participants at the measurement date (exit price).
We classify the inputs used to measure fair value into the folff
lowing hierarchy:
• Level 1: Inputs based on quoted market prices in active markets forff
identical assets or liabia lities at the measurement
date.
• Level 2: Inputs based on quoted prices for similar assets or liabilities in active markets, quoted prices for identical or
similar assets and liabilities in markets that are not active or other inputs that are observable and can be corroborated
by observable market data.
• Level 3: Inputs that reflect management’s best estimates and assumptim ons of what market participants would use in
pricing the asset or liability at the measurement date. The inputs are unobservable in the market and significant to the
valuation of the instruments.
Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments
from one fair value level to another. In such instances, the transfer would be reported at the beginning of the period in which the
change occurs.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Brigham Minerals had no financial assets or liabilities that were accounted forff
at fair value on a recurring basis at
December 31, 2020 and 2019.
Brigham Minerals had no derivative contracts in place as of December 31, 2020 and 2019 as disclosed in "Note 5—
Derivative Instruments." Commodity derivative instruments are valued using a third-party industry-standard pricing model
using contract terms and prices and assumptim ons and inputs that are substantially observable in active markets throughout the
F-19
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
BRIGHAM MINERALSRR
, INC.
full term of the instruments, including forward oil and gas price curves, discount rates and volatility factors. The fair values are
also compared to the values provided by the counterparties forff
the counterparties’ credit
quality forff
derivative liabilities. As such, these derivative contracts are classifiedff
within Level 2.
derivative assets and our credit quality forff
ness and are adjusted forff
reasonablea
Brigham Minerals had no transfers into or out of Level 1 and no transfers into or out of Level 2 forff
the years ended
December 31, 2020 and 2019.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Certain nonfinancial assets and liabilities, such as assets and liabilities acquired in a business combination, are measured
at fair value on a nonrecurring basis on the acquisition date and are subject to fair value adjustments under certain
circumstances. The inputs used to determine such fair value are primarily based upon internally developed cash flowff
models
and include factors such as estimates of economic reserves, future operating and development costs, future commodity prices
and a risk-adjusted discount rates, and are classified within Level 3.
Fair Value of Other Financial Instruments
The carrying value of cash, trade and other receivables and trade payablea
s are considered to be representative of their
respective fair values dued
of these instruments. The carrying amount of debt outstanding pursuant to our
term loan and our revolving credit facility approximates fair value as interest rates on these instruments approximate current
market rates. We categorized our long-term debt within Level 2 of the fair value hierarchy.
to the short-term naturet
7.
Long-Term Debt
Prior Revolving Credit Facilitytt
Prior to its termination on July 27, 2018, the Minerals Subsidiaries maintained a secured revolving credit facility with a
syndicate of financial instituti
ons (the “prior revolving credit facility”), which had been amended periodically. The prior
revolving credit facility had a commitment of $150 million, and a borrowing base and outstanding borrowings of $70 million
each as of July 27, 2018. Brigham Minerals terminated the prior revolving credit facility on July 27, 2018 with proceeds from
the Owl Rock credit facility (as defined below). Additionally, during the third quarter of 2018, Brigham Resources wrote off
approximately $0.3 million of unamortized debt issuance costs that were related to the prior revolving credit facility.
t
Owl Rock Credit Facilitytt
ility
On July 27, 2018, the prior revolving credit facility was terminated in conjunction with the entry into a new credit facff
(the “Owl Rock credit facility”) with Owl Rock Capital Corporation as administrative agent and collateral agent. Brigham
Resources used the proceeds from the Owl Rock credit facility to repay the outstanding $70 million of principal under the prior
revolving credit facility and to fundff
mineral and royalty acquisitions. The Owl Rock credit facility was subject to customary
fees, guarantees of subsidiaries, restrictions and covenants, including certain restricted payments, and was collateralized by
certain oil and natural
a $125 million initial
gas properties of Brigham Resources. The Owl Rock credit facility provided forff
term loan, a $75 million delayed draw term loan (“DDTL”) and a $10 million revolving credit facility, bore interest at a rate per
annum equal to, at Brigham Resources’ option, (a) the base rate plus 4.50%, or (b) the adjusted LIBOR rate forff
such interest
period (subject to a 1.00% floor) plus 5.50%, matured on July 27, 2024 and required Brigham Resources to maintain
compliance with certain financial and collateral coverage ratios.
t
On May 7, 2019, the Owl Rock credit facility was terminated and paid off using a portion of the net proceeds generated
from the IPO. As a result of the debt repayment, Brigham Minerals recognized a loss on extinguishment of debt of $6.9 million,
which consisted of a $4.0 million write-off of capita
alized debt issuance costs, a $2.1 million prepayment fee and legal fees of
$0.8 million.
Revolving Credit Facilitytt
On May 16, 2019 (the “closing date”) Brigham Resources entered into a credit agreement with Wells Fargo Bank, N.A.,
as administrative agent for the various lenders from time to time party thereto, providing for a new revolving credit facff
ility (our
"revolving credit facility”). Our revolving credit facility is guaranteed by Brigham Resources’ domestic subsidiaries and is
collateralized by a lien on substantially all of Brigham Resources and its domestic subsidiaries’ assets, including substantially
all of their respective royalty and mineral properties.
F-20
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Availability under our revolving credit facility is governed by a borrowing base, which is subject to redetermination in
May and November of each year. In addition, lenders holding two-thirds of the aggregate commitments may request one
additional redetermination each year. Brigham Resources can also request one additional redetermination each year, and such
other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to further
asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of
adjustments forff
permitted additional indebtedness. Increases to the borrowing base require unanimous approval of the lenders, while decreases
only require approval of lenders holding two-thirds of the aggregate commitments at such time. As of December 31, 2020, the
borrowing base on our revolving credit facility was $135.0 million, with outstanding borrowings of $20.0 million, resulting in
$115.0 million availabila
future borrowings.
ity forff
Our revolving credit facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the
margin is based on utilization of our revolving credit facility
adjusted LIBOR rate plus an applicable margin. The applicablea
and ranges fromff
(a) in the case of adjusted base rate loans, 0.750% to 1.750% and (b) in the case of adjusted LIBOR rate loans,
1.750% to 2.750%. Brigham Resources may elect an interest period of one, two, three, six, or if available to all lenders, twelve
months. Interest is payablea
in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee
quarterly in arrears on the daily undrawn available commitments under our revolving credit facility in an amount
is payablea
ranging from 0.375% to 0.500% based on utilization of our revolving credit facility. Our revolving credit facility is subjec
t to
other customary fee, interest and expense reimbursement provisions.
u
Our revolving credit facility matures on May 16, 2024. Loans drawn under our revolving credit facility may be prepaid at
any time without premium or penalty (other than customary LIBOR breakage) and must be prepaid in the event that exposure
ity at such time. The principal amount of loans that are prepaid
exceeds the lesser of the borrowing base and the elected availabila
are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be
reborrowed. In addition, Brigham Resources may permanently reduce or terminate in full
the commitments under our revolving
credit facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid.
Upon the occurrence of an event of default under our revolving credit facility, the administrative agent acting at the direction of
the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all
commitments under our revolving credit facility, provided that such acceleration and termination occurs automatically upon
the
occurrence of a bankruptcy or insolvency event of default.
u
ff
Our revolving credit facility contains customary affirmative and negative covenants, including, without limitation,
reporting obligations, restrictions on asset sales, restrictions on additional debt and lien incurrence and restrictions on making
distributions (subject only to no default or borrowing base deficiency) and investments. In addition, our revolving credit facility
requires us to maintain (a) a current ratio of not less than 1.00 to 1.00 and (b) a ratio of total net funded debt to consolidated
EBITDA of not more than 4.00 to 1.00. As of December 31, 2020, we were in compliance with all covenants in accordance
with our revolving credit facility.
8.
Shareholders' and Members' Equity
Shareholders' Equity
CC
Class A Common
Stock
Brigham Minerals has approximately 43.6 million shares of its Class A common stock outstanding as of December 31,
2020. Holders of Class A common stock are entitled to one vote per share on all matters to be voted upon
by the stockholders
and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. Upon liquidation,
dissolution, distribution of assets or other winding up, the holders of Class A common stock are entitled to receive ratably the
assets available forff
distribution to the stockholders after payment of liabilities.
u
CC
Class B Common
Stock
Brigham Minerals has approximately 13.2 million shares of its Class B common stock outstanding as of December 31,
by the
2020. Holders of the Class B common stock are entitled to one vote per share on all matters to be voted upon
stockholders. Holders of Class A common stock and Class B common stock generally vote together as a single class on all
matters presented to Brigham Minerals’ stockholders for their vote or approval. Holders of Class B common stock generally do
not have any right to receive dividends or distributions upon a liquidation or winding up of Brigham Minerals.
u
Treasury Stock
F-21
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Brigham Minerals repurchased 436,630 shares of its Class A common stock fromff
the September 2020 Selling
Shareholders at a price of $8.08 per share (and Brigham LLC redeemed a corresponding number of Brigham LLC Units held by
Brigham Minerals). See "Note 1—Business and Basis of Presentation." As of December 31, 2020, there were 436,630 shares of
Class A common stock held in treasury.
Earnings per Share
Basic earnings per share (“EPS”) measures the performance of an entity over the reporting period. Diluted earnings per
share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common
shares that were outstanding during the period. Brigham Minerals uses the “if-converted” method to determine the potential
dilutive effect of exchanges of outstanding shares of Class B common stock (and corresponding Brigham LLC Units), and the
treasury stock method to determine the potential dilutive effect
of vesting of its outstanding RSAs, RSUs, PSUs and unvested
Incentive Units. Brigham Minerals does not use the two-class method because the Class B common stock and the unvested
share-based awards are nonparticipating securities. For the year ended December 31, 2020, the Class B common stock, the
Incentive Units, RSAs and RSUs were not recognized in dilutive EPS calculations as the effect would have been antidilutive.
For the year ended December 31, 2019, Brigham Minerals’ EPS calculation includes only its share of net income forff
the period
subsequent to the IPO, and omits income or loss prior to the IPO. In addition, the basic weighted average shares outstanding
calculation is based on the actual days in which the shares were outstanding from the IPO through December 31, 2019. There
were no shares of Class A or Class B common stock outstanding for the year ended December 31, 2018, therefore no earnings
per share information has been presented forff
the indicated period.
ff
The following tablea
reflects the allocation of net income (loss) to common shareholders and EPS computations for the
period indicated based on a weighted average number of common stock outstanding for the period:
(In thousands, except per share data)
Basic EPS
Numerator:
Years Ended December 31,
2020
2019
2018
Basic net (loss) income attributable to Brigham Minerals, Inc. shareholders
$
(42,412) $
6,901
$
Less net income attributable to shareholders pre-IPO
—
Basic net (loss) income attributable to Brigham Minerals, Inc. shareholders post-IPO (1)
(42,412)
(848)
6,053
Denominator:
Basic weighted average shares outstanding (1)
Net (loss) income per common share
Numerator:
Diluted EPS
Basic net (loss) income attributable to Brigham Minerals, Inc. shareholders post-IPO (1)
Diluted net (loss) income attributable to Brigham Minerals, Inc. shareholders
Denominator:
Basic weighted average shares outstanding (1)
Effect of dilutive securities:
Diluted weighted average shares outstanding
Net (loss) income per common share
38,178
22,870
$
(1.11) $
0.26
$
(42,412)
(42,412)
38,178
—
38,178
6,053
6,053
22,870
—
22,870
$
(1.11) $
0.26
$
—
—
—
—
—
—
—
—
—
—
—
(1) - Represents earnings per share of Class A common stock and weighted average shares of Class A common stock for the period following
the IPO.
As of December 31, 2020, there were 1,187,811 shares related to PSUs (based on target), that could vest in the future
dependent on predetermined performance goals. These units were not included in the computation of EPS for the year ended
December 31, 2020, because the performanc
e goals had not been met, assuming the end of the reporting period was the end of
the contingency period.
ff
F-22
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
9. Temporary Equity
Temporary equity represents the Original Owners’ 23.2% ownership of Brigham LLC, as of December 31, 2020. In
addition, the Original Owners own all of our Class B common stock. Each share of Class B common stock does not have any
economic rights but entitles its holder to one vote on all matters to be voted on by our stockholders, generally and a redemption
right into Class A shares. As discussed below, following the IPO:
• Each holder of Brigham LLC Units foll
other than Brigham Minerals and its subsidiaries,
t
received a number of shares of Class B common stock equal to the number of Brigham LLC Units held by such
Brigham Unit Holder following the IPO;
owing the restructuring,
ff
• Brigham Minerals contributed, directly or indirectly, the net proceeds of the IPO to Brigham LLC in exchange for an
additional number of Brigham LLC Units such that Brigham Minerals holds, directly or indirectly, a total number of
Brigham LLC Units equal to the number of shares of Class A common stock outstanding following the IPO; and
ff
• Under the Amended and Restated Limited Liability Company Agreement of Brigham LLC (the “Brigham LLC
Agreement”), each Brigham Unit Holder, subject to certain limitations, has a right (the “Redemption Right”) to cause
Brigham LLC to acquire all or a portion of its Brigham LLC Units for,
at Brigham LLC’s election, (i) shares of our
Class A common stock at a redemption ratio of one share of Class A common stock for each Brigham LLC Unit
redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar
transactions or (ii) an equivalent amount of cash. We will determine whether to issue shares of Class A common stock
or cash based on facts in existence at the time of the decision, which we expect would include the relative value of the
Class A common stock (including trading prices for the Class A common stock at the time), the cash purchase price,
the availabila
ity of other sources of liquidity (such as an issuance of preferred stock) to acquire the Brigham LLC Units
and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, Brigham Minerals
(instead of Brigham LLC) will have a call right to, for administrative convenience, acquire each tendered Brigham
LLC Unit directly from the redeeming Brigham Unit Holder for, at its election, (x) one share of Class A common stock
or (y) an equivalent amount of cash (the “Call Right”). The decision to make a cash payment upon a Brigham Unit
Holder’s exercise of its Redemption Right is required to be made by the Company’s directors who are independent
under Section 10A-3 of the Securities Act and do not hold any Brigham LLC Units subject to such redemption. In
connection with any redemption of Brigham LLC Units pursuant to the Redemption Right or acquisition pursuant to
our Call Right, the corresponding number of shares of Class B common stock will be cancelled.
Class B common stock is classified as temporary equity in the consolidated balance sheet as, pursuant to the Brigham
LLC Agreement, the Redemption Rights of each Brigham Unit Holder for either shares of Class A common stock or an
equivalent amount of cash is not solely within Brigham Minerals’ control. This is dued
to the fact that the holders of Class B
common stock control a majority of the votes of the board of directors through direct representation on the board of directors,
which allows the holders of Class B common stock to control the determination of whether to make a cash payment upon a
Brigham Unit Holder's exercise of its Redemption Right. Temporary equity is recorded at the greater of the carrying value or
redemption amount with a corresponding adjustment to additional paid-in capita
From the date of the IPO through
December 31, 2020, the Company recorded adjustmd
ents to the value of temporary equity as presented in the tablea
below:
al.
(In thousands)
Balance - April 17, 2019 (1)
Conversion of Class B shares to Class A shares
Net income attribution to temporary equity
Distribution to holders of temporary equity
Adjustment of temporary equity to redemption amount (2)
Balance - December 31, 2019
Conversion of Class B shares to Class A shares
Net loss attribution to temporary equity
Distribution to holders of temporary equity
Adjustment of temporary equity to redemption amount (3)
Balance - December 31, 2020
F-23
Temporary equity
adjustments
$
$
$
518,000
(104,390)
9,646
(20,321)
51,572
454,507
(97,491)
(15,582)
(24,793)
(170,361)
146,280
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
BRIGHAM MINERALSRR
, INC.
(1)
(2)
(3)
Based on 28,777,802 shares of Class B common stock outstanding and Class A share price of $18.00. In connection with the IPO, the balance
transferred from additional paid-in capital to temporary equity was the greater of redemption value or carrying value of the shares of Class B common
stock at IPO and included an initial upward adjustment to redemption amount totaling $194.5 million.
Based on 22,847,045 shares of Class B common stock outstanding and Class A share 10-day VWAP of $19.89 at December 31, 2019.
Based on 13,167,687 shares of Class B common stock outstanding and Class A share 10-day VWAP of $11.11 at December 31, 2020.
10. Share-Based Compensation
LLC Incentive Units
As part of the Second Amended and Restated Limited Liability Company Agreement of Brigham Resources, LLC dated
May 8, 2015, Brigham Resources authorized 120,000 restricted incentive units forff
issuance to management, independent
directors, employees, and consultants (such incentive units, as converted as described below, the “Incentive Units”). Brigham
Resources granted Incentive Units in April 2013 and September 2015 and 2018. In connection with the 2018 corporate
reorganizations and the corporate reorganization consummated in connection with Brigham Minerals’ IPO (collectively with
the 2018 corporate reorganizations, the “corpora
te reorganization”), these Incentive Units were converted into units in Brigham
Equity Holdings, LLC (“Brigham Equity Holdings”) with equivalent rights, responsibilities, and preferences. The Incentive
Units are subject to vesting as follows: 20% of the Incentive Units were vested on the date of grant and 20% of the Incentive
Units vest on each anniversary of the date of grant if the holder remains continuously employed by Brigham Resources or its
affiliates through the applicablea
vesting date. Upon vesting of the Incentive Units, holders of the Incentive Units receive one
share of Brigham Minerals’ Class B common stock and one Brigham LLC Unit for each vested Incentive Unit.
rr
In connection with the completion of the IPO, Brigham LLC and Brigham Equity Holdings discontinued granting new
Incentive Units; however Brigham Equity Holdings will continue to administer the existing awards that remain outstanding. As
discussed in “Note 9—Temporary Equity,” participants may receive one share of Brigham Minerals’ Class A common stock in
exchange for one share of Class B common stock and one Brigham LLC Unit, or cash at the option of Brigham Minerals.
Brigham Minerals accounts for the Incentive Units as compensation cost measured at the fair value of the award on the date of
.
grant. No compensation expense was recognized prior to the IPO because the IPO was not considered probablea
A summary of the Incentive Unit activity forff
the year ended December 31, 2020 is as follows:
Outstanding—January 1, 2020
Vested
Outstanding—December 31, 2020
Long Term Incentive Plan
Incentive Units
Number of Incentive
Units
Grant-date Fair
Value
212,733
(70,913)
141,820
$
$
$
10.04
10.04
10.04
In connection with the IPO, Brigham Minerals adopted the Brigham Minerals, Inc. 2019 Long Term Incentive Plan
(“LTIP”) for employees, consultants and directors who perform services for Brigham Minerals. The LTIP provides forff
issuance
of awards based on shares of Class A common stock. Brigham Minerals has issued restricted stock awards ("RSAs"), restricted
stock units ("RSUs") and performance-based vesting units ("PSUs") under the LTIP. The shares to be delivered under the LTIP
shall be made available fromff
(i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued
shares reacquired by Brigham Minerals including shares purchased on the open market. A total of 5,999,600 shares of Class A
issuance under the LTIP. At December 31, 2020, 3,548,923 shares of Class A common
common stock have been authorized forff
stock remained available forff
future grants. Currently, all outstanding RSAs, RSUs and PSUs granted under the LTIP are
entitled to receive dividends (in the case of RSAs) or have dividend equivalent rights (“DERs”), which entitle holders of RSUs
and PSUs to the same dividend value per share as holders of the Company’s Class A common stock. Such dividends and DERs
are subject to the same vesting and other terms and conditions as the corresponding unvested RSAs, RSUs, and PSUs.
Dividends and DERs are accumulated and paid when the underlying shares vest. The fair value of the RSA awards granted with
the right to receive dividends and RSU awards granted with the right to receive DERs are generally based on the trading price
of the Company’s Class A common stock as of the date of grant. Brigham Minerals accounts for the awards granted under the
LTIP as compensation cost measured at the fair value of the award on the date of grant. Brigham Minerals accounts for
forfeitures forff
each of the RSAs, RSUs, and PSUs as they occur.
F-24
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
RSAs are grants of shares of Class A common stock subject to a risk of forfeiture and restrictions on transferability. The
share-based compensation expense of such RSAs was determined using the closing price of Class A common stock on April 23,
2019, the date of grant, of $21.25. On April 23, 2019, 312,189 RSAs were granted and 152,742 RSAs vested immediately. The
RSAs generally vest in one-third increments on each of April 23, 2020, 2021 and 2022 and are subject to restrictions on
transfer and are generally subject to a risk of forfeiture if the award recipient ceases providing services to Brigham Minerals
prior to the lapsea
of such restrictions.
A summary of the RSA activity for the year ended December 31, 2020 is as follow
ff
s:
Unvested at January 1, 2020
Vested
Forfeited
Unvested at December 31, 2020
Restricted Stock Awards
Number of RSAs
Grant Date Fair Value
148,456
$
(69,594) $
(10,569) $
68,293
$
21.25
21.25
21.25
21.25
RSUs represent the right to receive shares of Class A common stock at the end of the vesting period in an amount equal
to the number of RSUs that vest. The RSUs that have been granted generally vest in one-third increments on each of the first
three anniversaries of the grant date and are subject to restrictions on transfer and are generally subject to a risk of forfeiture if
the award recipient ceases providing services to Brigham Minerals prior to the date the award vests. The share-based
compensation expense of the RSUs is determined using the closing share price on the date of grant applied to the total number
of RSUs granted. Brigham Minerals accounts for forfeitures as they occur. Brigham Minerals withheld 88,476 RSUs to satisfy
employee tax withholding obligations totaling $1.0 million, related to the RSUs that vested in 2020.
A summary of the RSU activity for the year ended December 31, 2020 is as follows:
Unvested at January 1, 2020
Granted
Vested
Forfeited
Unvested at December 31, 2020
Restricted Stock Units
Number of RSUs
Grant Date Fair Value
415,815
555,534
$
$
(392,528) $
(15,950) $
562,871
$
21.25
16.41
19.36
20.57
17.81
PSUs represent the right to receive shares of Class A common stock at the end of a specified performance period.
753,546 PSUs (based on target) were granted on April 23, 2019, with a performance period that ends on December 31, 2021.
During the year ended December 31, 2020, 434,265 PSUs (based on target) were granted with a performance period that ends
on December 31, 2022. The terms and conditions of the PSUs allow for vesting of the awards ranging between 0% (or
forfeiture) and 200% of target. The vesting level is calculated based on the actual total stockholder returnt
achieved during the
performance period including projected dividends. The fair value of such PSUs was determined using a Monte Carlo simulation
perforff mance period. The Monte Carlo simulation model utilizes multiple input
and will be recognized over the applicablea
variables that determine the probability of satisfying the market condition stipulated in the award to calculate the fair value of
the award. Expected volatilities in the model were estimated using a historical period consistent with the perforff mance period of
approximately three years. The risk-freff e interest rate was based on the United States Treasury rate forff
a term commensurate
below, Brigham Minerals estimated the fair value of
with the expected life off
PSUs to be $15.98 and $20.36, respectively, for PSUs granted in 2020 and 2019, respectively.
f the grant. Using the assumptions in the tablea
Expected dividend yield
Risk-free interest rate
Volatility
F-25
Years Ended December 31,
2020
2019
11.5 %
1.4 %
35 %
8.1 %
2.3 %
30 %
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
BRIGHAM MINERALSRR
, INC.
A summary of the PSU activity for the year ended December 31, 2020 is as follows:
Unvested at January 1, 2020
Granted
Unvested at December 31, 2020
e
Share-Based Compensation Expens
x
Performance-Based Restricted Stock Units
Target PSUs
Estimated Earned PSUs Grant Date Fair Value
753,546
434,265
1,187,811
450,836
174,106
624,942
$
$
$
20.36
15.98
19.14
Share-based compensation expense is included in general and administrative expense in the Company’s consolidated and
ion award,
ion cost recorded for each type of share-based compensat
m
combined statement of operations. Share-based compensat
the periods indicated:
was as follows forff
m
(In thousands)
Incentive Units (1) (3)
RSAs (2) (3)
RSUs (3)
PSUs (4)
Capitalized share-based compensation (5) (6)
Total share-based compensation expense
Years Ended December 31,
2019
2020
2018
$
712
$
2,904
$
1,254
7,390
4,259
3,972
4,630
2,361
(6,086)
(3,818)
$
7,529
$
10,049
$
—
—
—
—
—
—
(1)
(2)
(3)
(4)
(5)
(6)
Includes a cumulative effect adjustment to share-based compensation cost of $2.0 million pertaining to the period from the grant date through the IPO
date. No compensation expense was recorded prior to the IPO because the IPO was not considered probable.
Includes $3.2 million recorded at grant date of April 23, 2019, associated with 152,742 RSAs, which vested immediately during the year ended
December 31, 2019.
Share-based compensation expense relating to Incentive Units, RSAs, and RSUs with ratable vesting is recognized on a straight-line basis over the
requisite service period for the entire award.
Share-based compensation expense relating to PSUs with cliff-vesting is recognized on a straight-line basis over the performance period for the entire
award.
During the year ended December 31, 2020, Brigham Minerals capitalized $3.0 million of the share-based compensation to unevaluated property and
$3.0 million to evaluated property on its consolidated balance sheet.
Brigham Minerals capitalizes a portion of the share-based compensation cost incurred after the IPO.
In addition to the time-based vesting conditions described above
a
, the Incentive Units could be earned upon the
completion of an initial public offering or another liquidity event, considered a performance condition, which was not deemed
probable and therefore no compensation expense was recognized prior to December 31, 2018.
Future Share-Based Compensation Expex nse
The following tablea
reflects the future share-based compensat
m
ion expense to be recorded forff
the share-based
compensation awards that were outstanding at December 31, 2020, a portion of which will be capia talized:
(In thousands)
Incentive Units
RSAs
RSUs
PSUs
Total
712
534
$
1,246
$
726
225
951
$
6,851
2,653
9,504
4,374
966
$
5,340
$
12,663
4,378
17,041
Year
2021
2022
Total
11.
Income Taxes
The Company accounts forff
recognized for the future tax consequences attributablea
existing assets and liabilities and their respective tax bases. Deferre
income taxes using the asset and liability method. Deferred tax assets and liabilities are
to differences between the financial statement carrying amounts of
d tax assets and liabilities are calculated by applying existing
ff
F-26
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
BRIGHAM MINERALSRR
, INC.
y to taxable income in the years in which those temporary differences are expected to be
tax laws and the rates expected to appl
recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the
period that includes the enactment date.
a
Brigham Minerals periodically assesses whether it is more likely than not that it will generate sufficient taxable income to
realize its deferred income tax assets, including net operating losses. In making this determination, Brigham Minerals considers
all available positive and negative evidence and makes certain assumptim ons. Brigham Minerals considers, among other things,
its deferred tax liabia lities, the overall business environment, its historical earnings and losses, current industry trends and its
outlook for future years. Brigham Minerals' management believes that it is more likely than not that the results of future
operations will generate suffiff cient taxable income to realize the deferred tax assets and as a result, Brigham Minerals did not
record a valuation allowance at December 31, 2020 and 2019.
Brigham Minerals has evaluated all tax positions for which the statute of limitations remains open and believes that the
material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2020 and 2019,
Brigham Minerals had not establia
nor recorded any unrecognized benefits related to, uncertain tax
positions.
shed any reserves for,
ff
Brigham Resources, the Company’s predecessor, is a limited liability company that is not subject to U.S. federal income
tax, but is subject to the Texas Margin Tax and state income taxes in Oklahoma, North Dakota, and Colorado. As part of the
corporate reorganization, certain entities affiliated with Warburg Pincus contributed all of their respective interests in certain
wholly owned “blocker” entities through which they held interests in Brigham Resources to Brigham Minerals in exchange for
all of the outstanding shares of common stock of Brigham Minerals. On the date of the corporate reorganization, a
sh a net deferred tax liabia lity for
corresponding “first day” tax charge of approximately $3.1 million was recorded to establia
differences between the tax and book basis of the investment in Brigham Resources. The offset of the deferred tax liabia lity was
recorded to additional paid-in-capital.
Brigham Minerals is a corporation and is subject to U.S. federal income tax. In April 2019, Brigham Minerals completed
the IPO of 16,675,000 shares of Class A common stock at a price to the public of $18.00 per share. The tax implications of the
as a taxable corporation subject to U.S. federal income
July 2018 restructuring, IPO and the tax impact of the Company’s statust
ncial statements. On IPO date, a corresponding tax
tax have been reflected
benefit of approximately $13.7 million was recorded associated with the difference
s between the tax and book basis of the
investment in Brigham Resources. The offset of the deferred tax asset was recorded to additional paid-in capia tal.
in the accompanying consolidated and combined finaff
ff
ff
After the December 2019 Offering, as discussed in "Note 1—Business and Basis of Presentation", a corresponding tax
benefit of approximately $9.5 million was recorded associated with the difference
s between the tax and book basis of the
investment in Brigham Resources. After the June 2020 Secondary Offering and September 2020 Secondary Offering, and
corresponding redemptions, as discussed in "Note 1—Business and Basis of Presentation", a corresponding reduction to the tax
benefit of approximately $0.8 million and $2.8 million, respectively, was recorded associated with the difference
s between the
tax and book basis of the investment in Brigham Resources. The offset of the deferred tax asset was recorded to additional paid-
in capita
al.
ff
ff
The effective combined U.S. federal and state income tax rate for the year ended December 31, 2020 was 18%. During
the year ended December 31, 2020, the Company recognized income tax benefitff of $12.8 million. During the years ended
December 31, 2019 and 2018, the Company recognized income tax expense of $2.7 million and $0.3 million, respectively.
Total income tax expense for the years ended December 31, 2020, 2019 and 2018 differed from amounts computed by applying
the U.S. federal statutory tax rate of 21% due to the impact of the temporary equity, net income attributable to Predecessor, state
taxes (net of the anticipated fede
ral benefit), and percentage depletion in excess of basis.
ff
F-27
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(In thousands)
State Income Tax
Current expense/(benefit)
Deferred (benefit)/expense
Federal Income Tax
Current (benefit)/expense
Deferred (benefit)/expense
Totals:
Total current income tax (benefit)/expense
Total deferred income tax (benefit)/expense
Totals:
Years Ended December 31,
2020
2019
2018
$
122
$
692
$
(1,876)
63
(23)
(138)
(2,942)
(8,066)
1,322
602
$ (12,762) $
2,679
$
(2,820) $
2,014
(9,942)
665
$ (12,762) $
2,679
$
$
$
114
374
327
91
236
327
The following tabla e reconciles the income tax provision with income tax expense at the federal statutory
t
rate for the
periods indicated:
(In thousands)
(Loss) income before income taxes
Less: income before income taxes attributable to predecessor
Less: loss (income) before income taxes attributable to temporary equity
(Loss) income before income taxes attributable to shareholders
Income tax at the federal statutory rate
State income taxes, net of federal benefit
Other federal tax effects
Percentage depletion in excess of basis
Total income tax provision
Years Ended December 31,
2020
2019
$ (70,756) $
—
15,270
24,318
(5,118)
(9,858)
$ (55,486) $
9,342
$ (11,652) $
1,962
(1,223)
113
—
717
—
—
$
$
$
$ (12,762) $
2,679
$
2018
33,142
(30,805)
—
2,337
491
(150)
—
(14)
327
Brigham Minerals had $24.9 million and $18.8 million recorded as deferred tax asset as of December 31, 2020 and 2019.
The tax effects of temporary
m
differences that give rise to significant portions of the deferre
ff
d tax assets were are folff
lows:
(In thousands)
Deferred tax assets:
Loss carryforwards
Investment in subsidiary
Total deferred tax assets:
Deferred tax liabilities:
Oil and gas properties
Investment in subsidiary
Total deferred tax liabilities
12.
Commitments and Contingencies
Commitments
Years Ended December 31,
2020
2019
$
$
$
$
627
24,405
25,032
$
$
—
19,021
19,021
(112) $
—
(112) $
(198)
—
(198)
Brigham Minerals leases office space under operating leases. Rent expense forff
the year ended December 31, 2020, 2019,
and 2018 was $1.1 million, $0.6 million, and $0.3 million, respectively. Future minimum lease commitments under
noncancelablea
operating leases at December 31, 2020 are presented below (in thousands):
F-28
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
BRIGHAM MINERALSRR
, INC.
Year
2021
2022
2023
2024
2025
2026 and Thereafter
Total
Contingencies
Commitment
1,272
1,310
1,347
1,383
1,419
2,251
8,982
$
$
$
Brigham Minerals may, froff m time to time, be a party to certain lawsuits and claims arising in the ordinary course of
business. The outcome of such lawsuits and claims cannot be estimated with certainty and management may not be able to
estimate the range of possible losses. Brigham Minerals records reserves for contingencies when information available indicates
that a loss is probable and the amount of the loss can be reasonably estimated. Brigham Minerals had no reserves forff
contingencies at December 31, 2020 and December 31, 2019.
13. Related-Party Transactions
Brigham Land Management (“BLM”) occasionally provides us with land brokerage services. The services are provided at
market prices and are periodically verified by third-party quotes. BLM is owned by Vince Brigham, an advisor to us and
brother of Ben M. Brigham, founder and Executive Chairman of the Board. For the year ended December 31, 2020, the
amounts paid to BLM for land brokerage services were immaterial. For the years ended December 31, 2019 and 2018, the
amounts paid to BLM for land brokerage services were $0.1 million and $0.1 million, respectively. At December 31, 2020 and
2019, the liabilities recorded for services performed by BLM during the respective periods were immaterial.
Brigham Exploration Company, partially owned by Ben M. Brigham, on occasion leases some of our acreage at market
rates. Brigham Minerals did not lease any acreage to Brigham Exploration Company during the years ended December 31, 2020
and 2018. We received $0.4 million for the year ended December 31, 2019 in connection with such leases.
The Company is party to a services agreement with RS Energy Group, which provides the Company with certain
software and services that assist in evaluating the acquisition of mineral interests. Warburg Pincus owned a controlling stake in
RS Energy Group until February 2020. The service feeff
s incurred under this agreement were $0.1 million and $0.2 million for
the years ended December 31, 2020 and 2019.
During the year ended December 31, 2018, Brigham Resources borrowed $7.0 million from Brigham Operating, at an
interest rate of 7.00% and repaid the loan prior to December 31, 2018.
14.
COVID-19 Pandemic and Impact on Global Demand forff Oil and Natural Gas
t
The ongoing global spread of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, has caused a
gas industry and to our business by, among other things, contributing to a significant
continuing disruption to the oil and natural
decrease in global crude oil demand and the price forff
h
oil beginning in the firff st quarter of 2020 and continuing through the fourt
quarter of 2020. The declining commodity prices have adversely affected the revenues the Company receives for its royalty
al markets on terms favorable to the Company. Additionally, in response
interests and could affect its abila
to the decline in commodity prices, many operators on the Company's properties have announced reductions in their estimated
2021 and beyond, which has and will adversely affect the near-term development of the Company's
capita
the second half of the year and into 2021. While these lower commodity prices initially resulted in some of
properties during
the Company's operators shutting in or curtailing production from wells on its properties during
the second quarter of 2020, we
saw a majority of the Company’s operators resume production for previously curtailed and shut in wells in connection with the
improvement of commodity prices in the second half of 2020.
ity to access the capita
al expenditures forff
d
d
ff
In response to the COVID-19 pandemic, the potential risk to Brigham Minerals' workforce and in compliance with stay at
for all of its employees to
home orders, the Company successfully implemented policies and the technological infrastructuret
work from home in the first quarter of 2020 and ceased all business travel. In compliance with the requirements for the re-
F-29
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
ity while continuing to support
opening of the Texas economy, the Company is currently operating its office at 75% capac
remote working for its employees that are considered high-risk pursuant to the Center forff Disease Control and Prevention
guidelines or have household members meeting the criteria of those guidelines. Due to these efforts, the Company has not
experienced material disruptions to its operations or the health of its workforce and has maintained the engagement and
connectivity of its personnel.
a
15. Subsequent Events
On February
rr
19, 2021, Brigham Minerals declared a dividend of $0.26 per Class A common stock payablea
on March 26,
2021, to stockholders of record at the close of business on March 19, 2021.
16. Quarterly Financial Information-Unaudited
Summarized quarterly finaff
ncial data forff
the years ended December 31, 2020 and 2019 are presented in the following
s. During the periods presented below, earnings per share information is not available dued
to no shares being recognized
tablea
for accounting purposes forff
periods prior to the IPO.
(In thousands, except per share amount)
Year ended December 31, 2020:
Total revenues
Income (loss) from operations - (3)
Net income (loss)
Year ended December 31, 2019:
Total revenues
Income from operations
Net income (loss)
Net income (loss) attributable to Brigham Minerals, Inc.
Basic EPS attributable to Brigham Minerals, Inc. shareholders
Diluted EPS attributable to Brigham Minerals, Inc. shareholders
$
$
Net income (loss) attributable to Brigham Minerals, Inc. - (2)
Basic EPS attributable to Brigham Minerals, Inc. shareholders - (1)
Diluted EPS attributable to Brigham Minerals, Inc. shareholders - (1)
$
$
Quarter
First
Second
Third
Fourth
$
32,280
$
12,605
$
23,078
$
23,760
10,413
8,801
4,706
0.14
0.14
(7,144)
(6,816)
(4,050)
(15,885)
(13,017)
(9,465)
$
$
(0.11) $
(0.11) $
(0.24) $
(0.24) $
$
18,265
$
24,529
$
25,107
$
8,707
4,036
534
— $
— $
5,034
(3,207)
(1,856)
(0.12) $
(0.12) $
9,115
8,464
3,146
0.14
0.14
$
$
(57,678)
(46,962)
(33,603)
(0.78)
(0.78)
33,614
14,362
12,346
5,077
0.20
0.20
(1) Represents earnings per share of Class A common stock and weighted average shares of Class A common stock for the period from April 17, 2019 through
December 31, 2019, the period following the IPO. See "Note 8— Shareholders' and Members' Equity" for additional information.
(2) Represents net income attributable to Brigham Minerals for the period starting with the completion of the July 2018 restructuring. See "Note 1—Business
and Basis of Presentation" for additional information.
(3) Third and fourth quarters of 2020 include $18.9 million and $60.7 million of impairment of oil and gas properties, respectively. See "Note 3—Oil and Gas
Properties" for further discussion of this transaction.
17.
Reserve and Related Financial Data (SMOG) -Unaudited
Oil and Natural Gas Reserves
gas and NGLs which, by analysis of geoscience and engineering data,
Proved reserves represent quantities of oil, natural
in the future from known reservoirs under existing economic
can be estimated with reasonable certainty to be recoverablea
conditions, operating methods and government regulations. Proved developed reserves are proved reserves which can be
t
F-30
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
and operating methods. Proved reserves
expected to be recovered through existing wells with existing equipment, infrastructuret
were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under
existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.
The reserves at December 31, 2020, 2019, and 2018 presented below were audited by CG&A. Estimates of proved
reserves are inherently imprecise and are continually subject to revision based on production history, results of additional
exploration and development, price changes and other facff
tors. The reserves are located in various fields in Texas, New Mexico,
Oklahoma, Colorado, Wyoming, North Dakota, and Montana. All of the proved reserves are located in the continental United
States.
Proved reserve quantities, December 31, 2017
Sales of minerals-in-place
Extensions and discoveries
Acquisitions
Revisions of previous estimates
Production
Proved reserve quantities, December 31, 2018
Sales of minerals-in-place
Extensions and discoveries
Acquisitions
Revisions of previous estimates
Production
Proved reserve quantities, December 31, 2019
Sales of minerals-in-place
Extensions and discoveries
Acquisitions
Revisions of previous estimates
Production
Proved reserve quantities, December 31, 2020
Proved reserve quantities at December 31, 2020 attributable to temporary
equity
Proved developed reserve quantities:
December 31, 2018
December 31, 2019
December 31, 2020
Proved developed reserves at December 31, 2020 attributable to
temporary equity
Proved undeveloped reserve quantities:
December 31, 2018
December 31, 2019
December 31, 2020
Proved undeveloped reserves at December 31, 2020 attributable to
temporary equity
Crude Oil
(MBbl)
Natural Gas
(MMcf)
NGL
(MBbl)
Total
(MBoe)
8,724
—
1,765
3,669
(390)
(777)
12,991
(182)
1,997
4,256
(586)
(1,515)
16,961
—
876
1,235
(4,049)
(1,823)
13,200
38,401
—
5,285
13,862
(3,245)
(2,507)
51,796
(697)
7,780
13,053
(5,495)
(4,707)
61,730
(286)
2,545
3,652
(18,188)
(5,809)
43,644
3,980
—
562
1,374
(577)
(222)
5,117
(110)
817
1,218
(797)
(407)
5,838
(1)
291
331
(1,189)
(680)
4,590
19,104
—
3,208
7,354
(1,508)
(1,417)
26,741
(409)
4,110
7,651
(2,299)
(2,706)
33,088
(48)
1,591
2,174
(8,271)
(3,471)
25,063
3,064
10,131
1,065
5,818
6,067
9,924
9,403
2,183
6,924
7,037
3,797
881
21,735
33,232
31,873
7,399
30,061
28,498
11,771
2,732
1,898
2,494
3,426
795
3,219
3,344
1,164
270
11,588
17,957
18,141
4,211
15,153
15,131
6,922
1,607
Changes in proved reserves that occurred during
d
2020 were primarily due to:
F-31
BRIGHAM MINERARR LS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
•
the acquisition of additional mineral interests located in the Permian, Anadarko, DJ and Williston Basins in multiple
transactions. The acquired proved reserves of 2,174 MBoe throughout the year were offset by the divestiture of 48
MBoe of proved reserves;
• well additions, extensions and discoveries of approximately 1,591 MBoe, as approximately 342 gross horizontal well
probable, possible and contingent resources to proved, due to continuous activity and
locations were converted fromff
delineation of additional zones on our mineral and royalty interests;
•
•
•
negative revisions of 2,645 MBoe attributable to reduction in SEC pricing;
as a result of decreased operator activity throughout 2020, a reclass of 7,036 MBoe to non-proved due to future
locations falling outside the SEC five-year ruler
for PUDs; and
positive revision of 1,410 MBoe attributablea
processing assumptions, and unit configuration.
to estimate ultimate recovery ("EUR") adjustments, refined gas and NGL
Changes in proved reserves that occurred during
d
2019 were primarily due to:
•
the acquisition of additional mineral interests located in the Permian, Anadarko, DJ and Williston Basins in multiple
transactions, which included 7,242 MBoe of additional proved reserves which is comprised of 7,651 MBoe of acquired
proved reserves and divestiture of 409 MBoe of proved reserves within the year;
• well additions extensions and discoveries of approximately 4,110 MBoe, as approximately 900 gross horizontal well
probable, possible and contingent resources to proved, due to continuous activity and
locations were converted fromff
delineation of additional zones on our mineral and royalty interests; and
•
net volume revisions of approximately 2,299 MBoe. These revisions were comprised of 902 MBoe of negative
revisions attributablea
to operator development timing, unit
configuration and EUR adjustments to existing proved locations.
to pricing as well as approximately 1,397 MBoe attributablea
Changes in proved reserves that occurred during 2018 were primarily dued
to:
•
the acquisition of additional mineral and royalty interests located in the Permian, DJ, Anadarko and Williston Basins in
multiple transactions, which included 7,354 MBoe of additional proved reserves;
• well additions, extensions and discoveries of approximately 3,208 MBoe, as 555 gross horizontal well locations were
probable, possible and contingent resources to proved, due to continuous activity and delineation of
converted fromff
additional zones on our mineral and royalty interests; and
•
net negative volume revisions of approximately 1,508 MBoe. These revisions were comprised of 536 MBoe of
positive revisions attributablea
to operator
development timing as well as 944 MBoe of revisions associated with unit configuration and EUR adjustments to
existing proved locations.
to pricing and were offset by negative revisions of 1,100 MBoe attributablea
Standardized Measure of Discounted Future Net Cash Flows
ff
Guidelines prescribed in FASB’s Accounting Standards Codification (“ASC”) Topic 932 Extractive Industries—Oil and
owed for computing a standardized measure of future net cash flows and changes therein relating to
are determined by applying prices and costs, including transportation, quality,
gas and NGLs to be produced in the future. The
Gas, have been foll
estimated proved reserves. Future cash inflows
and basis differentials, to the year-end estimated quantities of oil, natural
resulting futuret
net cash flows are reduced to present value amounts by applying a ten percent annual discount factor.
ff
t
The assumptim ons used to compute the standardized measure are those prescribed by the FASB and the SEC. These
assumptim ons do not necessarily reflect Brigham Resources’ expectations of actual revenues to be derived from those reserves,
nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally
applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation
process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more
shed proved producing oil and gas properties. Accordingly, these estimates are expected to
imprecise than estimates of establia
.
change as future information becomes availablea
F-32
BRIGHAM MINERALRR S, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
The folff
lowing summary sets forth the future net cash flows relating to proved oil and gas reserves based on
the standardized measure prescribed in ASC Topic 932:
(In thousands)
Future crude oil, natural gas, and NGL sales
Future severance tax and ad valorem taxes
Future income tax expense
Future net cash flows
10% annual discount
Standardized measure of discounted future net cash flows
Standardized measure of discounted future net cash flows attributable to
temporary equity
For the Year Ended December 31,
2020
2019
2018
562,545
(39,318)
(46,908)
476,319
(205,551)
270,768
66
62,853
$
$
$
1,042,118
(73,627)
(143,599)
824,892
(359,258)
465,634
186,999
$
$
$
1,049,141
(70,248)
(144,421)
834,472
(391,013)
443,459
—
$
$
$
The following prices were used in the determination of standardized measure:
Oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
For the Year Ended December 31,
2020
2019
2018
$
36.35
$
51.01
$
1.03
8.19
1.51
14.39
61.31
2.51
23.98
These prices were based on the 12-month arithmetic average first-of-month West Texas Intermediate (“WTI”) price of oil
gas. The NGL pricing varied by basin at 10% to 25% of WTI. All prices have been adjusted for
t
and Henry Hub price of natural
transportation, quality, basis differentials and post-production costs.
The principal sources of change in the standardized measure of discounted future
ff
net cash flows are:
(In thousands)
Standardized measure of discounted future net cash flows, beginning of
the year
For the Year Ended December 31,
2020
2019
2018
$
465,634
$
443,459
$
316,468
Changes in the year resulting from:
Sales, less production costs
Revisions of previous quantity estimates
Extensions, discoveries, and other additions
Net change in prices and production costs
Accretion of discount
Purchase of reserves in place
Divestitures of reserves in place
Net change in taxes
Timing differences and other
(73,654)
(135,926)
21,011
(131,886)
54,741
27,241
(250)
53,786
(9,929)
(86,492)
(41,539)
69,057
(99,660)
51,949
137,819
(5,783)
(5,739)
2,563
(52,278)
(22,942)
71,668
71,770
31,713
148,580
—
(75,369)
(46,151)
Standardized measure of discounted future net cash flows, end of the
year
$
270,768
$
465,634
$
443,459
Capitalized oil and natural gas costs
The aggregate amounts of costs capita
alized for oil and natural
t
gas producing activities and related aggregate amounts of
accumulated depletion follow:
F-33
BRIGHAM MINERALS, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(In thousands)
Oil and gas properties, at cost, using full cost method of accounting:
Not subject to depletion
Subject to depletion
Total oil and gas properties, at cost
Less accumulated depreciation, depletion, and amortization
Total oil and gas properties, net
For the Year Ended December 31,
2020
2019
2018
$
$
325,091
$
291,664
$
488,301
813,392
(189,546)
449,061
740,725
(61,103)
623,846
$
679,622
$
228,151
289,851
518,002
(27,628)
490,374
Costs incurred in oil and natural gas activities
The following costs were incurred in oil and natural
t
gas producing activities:
(In thousands)
Acquisition of oil and gas properties
Unevaluated
Evaluated
Total
For the Year Ended December 31,
2019
2018
2020
$
$
35,725
30,856
66,581
$
$
78,093
140,025
218,118
$
$
59,460
137,496
196,956
F-34
Board of
Directors
Senior
Leadership
Stockholder
Information
M.
“Bud”
Ben
Executive Chairman
Brigham
M.
“Bud”
Ben
Executive Chairman
Brigham
Robert M. Roosa
Chief Executive Offiff cer
Robert M. Roosa
Chief Executive Offiff cer
Harold D. Carter
Director
Carrie Clark
Director
Jon-Al Duplantier
Director
W. Howard Keenan Jr.
Director
Lance Langford
Director
James R. Levy
Director
Richard Stoneburner
Director
John R. “J.R.” Sult
Director
Geoff Boyd
Vice President of Acquisitions
S. Bradley Burris
Vice President of Land
Hamilton W. Hogsett
Vice President of Reservoir Engineering
Kevin J. L’abbé
Vice President of Exploration –
Oklahoma/Colorado
A. Dax McDavid
Vice President of Exploration –
Texas/North Dakota
Kari A. Potts
Vice President, General Counsel,
Compliance Officer & Secretary
Jordan K. Spearman
Vice President of Business Development
Blake C. Williams
Chief Financial Offiff cer
CORPORATE
HEADQUARTERS
5914 W. Courtyrr ard Drive
Suite 200
Austin, Texas 78730
(512) 220-6350
www.brighamminerals.com
ANNUAL MEETING
The 2021 Annual Meeting of
Stockholders will be held
virtually on
Wednesday, May 26, 2021,
at 1 p.m. CDT
STOCK EXCHANGE LISTING
New York Stock Exchange
Trading Symbol “MNRL”
TRANSFER AGENT AND
REGISTRAR
American Stock Transfer &
Trust Company
6201 15th Avenue
Brooklyn, New York 11219
INDEPENDENT AUDITOR
KPMG LLP
111 Congress Avenue
Suite 1900
Austin, Texas 78710
Brigham Minerals
5914 W. Courtyrr ard Dr.
Suite 200
Austin, TX 78730